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

FORM 10-Q


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

	For the Quarterly Period Ended~~June 30, 2014~~March 31, 2015
	ORor
£¨	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~~EVERSOURCE ENERGY (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

	Tx	£¨

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


	Yes	No

	Tx	£¨

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~~filer" and ~~large~~"large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):


	Large Accelerated Filer	Accelerated Filer	Non-accelerated Filer

~~Northeast Utilities~~Eversource Energy	Tx	£¨	£¨
The Connecticut Light and Power Company	£¨	£¨	Tx
NSTAR Electric Company	£¨	£¨	Tx
Public Service Company of New Hampshire	£¨	£¨	Tx
Western Massachusetts Electric Company	£¨	£¨	Tx

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


	Yes	No

~~Northeast Utilities~~Eversource Energy	£¨	Tx
The Connecticut Light and Power Company	£¨	Tx
NSTAR Electric Company	£¨	Tx
Public Service Company of New Hampshire	£¨	Tx
Western Massachusetts Electric Company	£¨	Tx

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


Company - Class of Stock	Outstanding as of ~~July 31, 2014~~April 30, 2015
~~Northeast Utilities~~Eversource Energy Common shares, $5.00 par value	~~316,385,790~~317,647,540 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~~Eversource Energy 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.

Eversource Energy, The Connecticut Light and Power Company, NSTAR Electric Company, Public Service Company of New Hampshire, and Western Massachusetts Electric Company each separately file this combined Form 10-Q. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.

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:~~
Current or former Eversource Energy companies, segments or investments:
ES, Eversource or the Company	Eversource Energy and subsidiaries
ES parent	Eversource Energy, a public utility holding company
ES parent and other companies	ES parent and other companies is comprised of ES parent, Eversource Service and other subsidiaries, which primarily includes our unregulated businesses, HWP Company, The Rocky River Realty Company (a real estate subsidiary), and the consolidated operations of CYAPC and YAEC
CL&P	The Connecticut Light and Power Company
~~CYAPC~~NSTAR Electric	~~Connecticut Yankee Atomic Power~~NSTAR Electric Company
~~Hopkinton~~NSTAR Gas	~~Hopkinton LNG Corp., a wholly owned subsidiary of Yankee Energy System, Inc.~~
~~HWP~~	~~HWP Company, formerly the Holyoke Water Power~~NSTAR Gas Company
~~MYAPC~~PSNH	~~Maine Yankee Atomic Power~~Public Service Company of New Hampshire
WMECO	Western Massachusetts Electric Company
~~NGS~~Yankee Gas	~~Northeast Generation~~Yankee Gas Services Company
ESTV	Eversource Energy Transmission Ventures, Inc., the parent company of NPT and Renewable Properties, Inc.
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~~Eversource Service	Northeast Utilities Service Company (effective January 1, 2014 includes the operations of NSTAR Electric & Gas)
~~NUTV~~NSTAR Electric & Gas	~~NU Transmission Ventures, Inc., the parent~~NSTAR Electric & Gas Corporation, a former Eversource Energy service company ~~of NPT and Renewable Properties, Inc.~~(effective January 1, 2014 merged into Northeast Utilities Service Company)
~~PSNH~~CYAPC	~~Public Service~~Connecticut Yankee Atomic Power Company ~~of New Hampshire~~
MYAPC	Maine Yankee Atomic Power Company
YAEC	Yankee Atomic Electric Company
Yankee Companies	CYAPC, YAEC and MYAPC
Regulated companies	NU'sThe ES 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:~~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:~~Other Terms and Abbreviations:
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,"~~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~~Work in ~~progress~~Progress
EPS	Earnings Per Share
ERISA	Employee Retirement Income Security Act of 1974
ES 2014 Form 10-K	~~Default~~The Eversource Energy ~~Service~~and Subsidiaries 2014 combined Annual Report on Form 10-K as filed with the SEC
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)
LBR	Lost Base Revenue
LNG	Liquefied natural gas
~~LOC~~	~~Letter of Credit~~
LRS	Supplier of last resort service
MGP	Manufactured Gas Plant
~~Millstone~~	~~Millstone Nuclear Generating station, made up of Millstone 1, Millstone 2, and Millstone 3. All three units were sold in March 2001.~~
MMBtu	One million British thermal units
~~Moody~~'sMoody's	~~Moody~~'sMoody's Investors Services, Inc.
MW	Megawatt
MWh	Megawatt-Hours
NEEWS	New England East-West Solution
Northern Pass	The high voltage direct current transmission line project from Canada into New Hampshire
NO_x	Nitrogen ~~oxide~~
~~NU 2013 Form 10-K~~	~~The Northeast Utilities and Subsidiaries 2013 combined Annual Report on Form 10-K as filed with the SEC~~oxides
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~~'sPoor'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~~EVERSOURCE ENERGY 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~~Eversource Energy and Subsidiaries (Unaudited)
Condensed Consolidated Balance Sheets	1
Condensed Consolidated Statements of Income	32
Condensed Consolidated Statements of Comprehensive Income	32
Condensed Consolidated Statements of Cash Flows	43

The Connecticut Light and Power Company (Unaudited)
Condensed Balance Sheets	4
Condensed Statements of Income	5
Condensed Statements of Comprehensive Income	5
~~Condensed Statements of Income~~	7
~~Condensed Statements of Comprehensive Income~~	7
Condensed Statements of Cash Flows	86

NSTAR Electric Company and Subsidiary (Unaudited)
Condensed Consolidated Balance Sheets	97
Condensed Consolidated Statements of Income	118
Condensed Consolidated Statements of Comprehensive Income	8
Condensed Consolidated Statements of Cash Flows	129

Public Service Company of New Hampshire and Subsidiary (Unaudited)
Condensed Consolidated Balance Sheets	1310
Condensed Consolidated Statements of ~~Inc~~o meIncome	1511
Condensed Consolidated Statements of Comprehensive Income	1511
Condensed Consolidated Statements of Cash Flows	1612

Western Massachusetts Electric Company (Unaudited)
Condensed Balance Sheets	1713
Condensed Statements of Income	1914
Condensed Statements of Comprehensive Income	1914
Condensed Statements of Cash Flows	2015

Combined Notes to Condensed Consolidated Financial Statements (Unaudited)	2116


ITEM 2– Management's Discussion and Analysis of Financial Condition and Results of Operations for the ~~following companies:~~Following Companies:
~~Northeast Utilities~~Eversource Energy and Subsidiaries	3930
The Connecticut Light and Power Company	5142
NSTAR Electric Company and Subsidiary	5444
Public Service Company of New Hampshire and Subsidiary	5646
Western Massachusetts Electric Company	5848

ITEM 3 – Quantitative and Qualitative Disclosures About Market Risk	6050

ITEM 4 – Controls and Procedures	6050

PART II – OTHER INFORMATION

ITEM 1 – Legal Proceedings	6151

ITEM 1A – Risk Factors	6151

ITEM 2– Unregistered Sales of Equity Securities and Use of Proceeds	6151

ITEM 6 – Exhibits	6252

SIGNATURES	6454

iii


NORTHEAST UTILITIES AND SUBSIDIARIES
EVERSOURCE ENERGY AND SUBSIDIARIES						EVERSOURCE ENERGY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS	CONDENSED CONSOLIDATED BALANCE SHEETS					CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)	(Unaudited)					(Unaudited)


		June 30,		December 31,				March 31,		December 31,
(Thousands of Dollars)	(Thousands of Dollars)	2014		2013		(Thousands of Dollars)		2015		2014

ASSETS	ASSETS					ASSETS

Current Assets:	Current Assets:					Current Assets:
	Cash and Cash Equivalents	$	34,096	$	43,364		Cash and Cash Equivalents	$	71,027	$	38,703
	Receivables, Net		807,510		765,391		Receivables, Net		1,131,434		856,346
	Unbilled Revenues		193,983		224,982		Unbilled Revenues		229,760		211,758
	Fuel, Materials and Supplies		281,721		303,233		Taxes Receivable		99,680		337,307
	Regulatory Assets		467,156		535,791		Fuel, Materials and Supplies		281,492		349,664
	Marketable Securities		115,987		92,427		Regulatory Assets		747,349		672,493
	Prepayments and Other Current Assets		168,022		121,861		Prepayments and Other Current Assets		231,949		226,194
Total Current Assets	Total Current Assets		2,068,475		2,087,049	Total Current Assets			2,792,691		2,692,465

Property, Plant and Equipment, Net	Property, Plant and Equipment, Net		17,978,692		17,576,186	Property, Plant and Equipment, Net			18,810,708		18,647,041

Deferred Debits and Other Assets:	Deferred Debits and Other Assets:					Deferred Debits and Other Assets:
	Regulatory Assets		3,339,457		3,758,694		Regulatory Assets		3,981,507		4,054,086
	Goodwill		3,519,401		3,519,401		Goodwill		3,519,401		3,519,401
	Marketable Securities		513,986		488,515		Marketable Securities		518,065		515,025
	Other Long-Term Assets		370,434		365,692		Other Long-Term Assets		329,393		349,957
Total Deferred Debits and Other Assets	Total Deferred Debits and Other Assets		7,743,278		8,132,302	Total Deferred Debits and Other Assets			8,348,366		8,438,469

Total Assets						Total Assets		$	29,951,765	$	29,777,975

LIABILITIES AND CAPITALIZATION						LIABILITIES AND CAPITALIZATION

Total Assets		$	27,790,445	$	27,795,537
Current Liabilities:						Current Liabilities:
						Notes Payable		$	1,003,500	$	956,825
						Long-Term Debt - Current Portion			245,583		245,583
						Accounts Payable			739,324		868,231
						Obligations to Third Party Suppliers			157,143		115,632
						Regulatory Liabilities			201,180		235,022
						Accumulated Deferred Income Taxes			218,582		160,288
						Other Current Liabilities			546,470		552,800
Total Current Liabilities						Total Current Liabilities			3,111,782		3,134,381

Deferred Credits and Other Liabilities:						Deferred Credits and Other Liabilities:
						Accumulated Deferred Income Taxes			4,574,630		4,467,473
						Regulatory Liabilities			524,940		515,144
						Derivative Liabilities			396,617		409,632
						Accrued Pension, SERP and PBOP			1,605,339		1,638,558
						Other Long-Term Liabilities			870,417		874,387
Total Deferred Credits and Other Liabilities						Total Deferred Credits and Other Liabilities			7,971,943		7,905,194

Capitalization:						Capitalization:
						Long-Term Debt			8,602,067		8,606,017

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

						Equity:
						Common Shareholders' Equity:
							Common Shares		1,668,039		1,666,796
							Capital Surplus, Paid In		6,241,417		6,235,834
							Retained Earnings		2,569,482		2,448,661
							Accumulated Other Comprehensive Loss		(72,414)		(74,009)
							Treasury Stock		(296,119)		(300,467)
						Common Shareholders' Equity			10,110,405		9,976,815
Total Capitalization						Total Capitalization			18,868,040		18,738,400

Total Liabilities and Capitalization						Total Liabilities and Capitalization		$	29,951,765	$	29,777,975

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

NORTHEAST UTILITIES AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

June 30,

December 31,
(Thousands of Dollars)
2014

2013

LIABILITIES AND CAPITALIZATION

Current Liabilities:

Notes Payable
$
905,000

$
1,093,000

Long-Term Debt - Current Portion

395,583

533,346

Accounts Payable

561,699

742,251

Regulatory Liabilities

359,921

204,278

Other Current Liabilities

580,605

702,776
Total Current Liabilities

2,802,808

3,275,651

Deferred Credits and Other Liabilities:


Accumulated Deferred Income Taxes

4,270,050

4,029,026

Regulatory Liabilities

503,955

502,984

Derivative Liabilities

449,439

624,050

Accrued Pension, SERP and PBOP

825,001

896,844

Other Long-Term Liabilities

882,688

923,053
Total Deferred Credits and Other Liabilities

6,931,133

6,975,957

Capitalization:

Long-Term Debt

8,147,129

7,776,833

Noncontrolling Interest - Preferred Stock of Subsidiaries

155,568

155,568

Equity:

  Common Shareholders' Equity:

Common Shares

1,666,637

1,665,351


Capital Surplus, Paid In

6,201,555

6,192,765

Retained Earnings

2,241,025

2,125,980

Accumulated Other Comprehensive Loss

(41,507)

(46,031)

Treasury Stock

(313,903)

(326,537)

Common Shareholders' Equity

9,753,807

9,611,528
Total Capitalization

18,056,504

17,543,929

Total Liabilities and Capitalization
$
27,790,445

$
27,795,537

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


EVERSOURCE ENERGY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)


				For the Three Months Ended March 31,
(Thousands of Dollars, Except Share Information)				2015		2014

Operating Revenues				$	2,513,431	$	2,290,590

Operating Expenses:
	Purchased Power, Fuel and Transmission				1,162,049		978,150
	Operations and Maintenance				333,382		351,688
	Depreciation				163,837		150,807
	Amortization of Regulatory Assets, Net				60,604		57,898
	Energy Efficiency Programs				146,603		138,825
	Taxes Other Than Income Taxes				149,481		145,533
			Total Operating Expenses		2,015,956		1,822,901
Operating Income					497,475		467,689

Interest Expense:
	Interest on Long-Term Debt				87,714		87,377
	Other Interest				7,129		2,598
		Interest Expense			94,843		89,975
Other Income, Net					5,727		1,667
Income Before Income Tax Expense					408,359		379,381
Income Tax Expense					153,226		141,545
Net Income					255,133		237,836
Net Income Attributable to Noncontrolling Interests					1,879		1,879
Net Income Attributable to Controlling Interest				$	253,254	$	235,957

Basic Earnings Per Common Share				$	0.80	$	0.75

Diluted Earnings Per Common Share				$	0.80	$	0.74

Dividends Declared Per Common Share				$	0.42	$	0.39

Weighted Average Common Shares Outstanding:
	Basic				317,090,841		315,534,512
	Diluted				318,491,188		316,892,119


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




CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

Net Income				$	255,133	$	237,836
Other Comprehensive Income, Net of Tax:
	Qualified Cash Flow Hedging Instruments				509		509
	Changes in Unrealized Gains on Other Securities				132		240
	Changes in Funded Status of Pension, SERP and PBOP Benefit Plans				954		961
Other Comprehensive Income, Net of Tax					1,595		1,710
Comprehensive Income Attributable to Noncontrolling Interests					(1,879)		(1,879)
Comprehensive Income Attributable to Controlling Interest				$	254,849	$	237,667


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

NORTHEAST UTILITIES AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

For the Three Months Ended June 30,

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

2013

2014

2013

Operating Revenues
$
1,677,614

$
1,635,862

$
3,968,204

$
3,630,885

Operating Expenses:

Purchased Power, Fuel and Transmission

624,211

488,302

1,602,362

1,236,111

Operations and Maintenance

373,234

357,169

724,922

703,261

Depreciation

152,207

159,553

303,014

314,530

Amortization of Regulatory Assets/(Liabilities), Net

(3,542)

54,574

54,356

108,623

Amortization of Rate Reduction Bonds

-

8,082

-

42,581

Energy Efficiency Programs

102,711

94,142

241,536

199,913

Taxes Other Than Income Taxes

134,803

123,464

280,335

256,345

Total Operating Expenses

1,383,624

1,285,286

3,206,525

2,861,364
Operating Income

293,990

350,576

761,679

769,521

Interest Expense:

Interest on Long-Term Debt

87,491

85,999

174,868

171,294

Other Interest

5,004

851

7,603

(8,188)

Interest Expense

92,495

86,850

182,471

163,106
Other Income, Net

5,526

4,944

7,194

12,710
Income Before Income Tax Expense

207,021

268,670

586,402

619,125
Income Tax Expense

77,774

95,606

219,319

216,093
Net Income

129,247

173,064

367,083

403,032
Net Income Attributable to Noncontrolling Interests

1,880

2,043

3,759

3,922
Net Income Attributable to Controlling Interest
$
127,367

$
171,021

$
363,324

$
399,110

Basic Earnings Per Common Share
$
0.40

$
0.54

$
1.15

$
1.27

Diluted Earnings Per Common Share
$
0.40

$
0.54

$
1.15

$
1.26

Dividends Declared Per Common Share
$
0.39

$
0.37

$
0.79

$
0.74

Weighted Average Common Shares Outstanding:

Basic

315,950,510

315,154,130

315,742,511

315,141,956

Diluted

317,112,801

315,962,619

317,002,461

315,982,578

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

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

Net Income
$
129,247

$
173,064

$
367,083

$
403,032
Other Comprehensive Income, Net of Tax:

Qualified Cash Flow Hedging Instruments

510

514

1,019

1,030

Changes in Unrealized Gains/(Losses) on Other Securities

218

(591)

458

(772)

Changes in Funded Status of Pension, SERP and PBOP Benefit Plans

2,086

1,506

3,047

3,127

Other Comprehensive Income, Net of Tax

2,814

1,429

4,524

3,385
Comprehensive Income Attributable to Noncontrolling Interests

(1,880)

(2,043)

(3,759)

(3,922)
Comprehensive Income Attributable to Controlling Interest
$
130,181

$
172,450

$
367,848

$
402,495

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


EVERSOURCE ENERGY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)



			For the Three Months Ended March 31,
(Thousands of Dollars)			2015		2014

Operating Activities:
	Net Income		$	255,133	$	237,836
	Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
		Depreciation		163,837		150,807
		Deferred Income Taxes		148,193		137,417
		Pension, SERP and PBOP Expense		26,495		24,995
		Pension and PBOP Contributions		(26,659)		(6,622)
		Regulatory Over/(Under) Recoveries, Net		(110,748)		872
		Amortization of Regulatory Assets, Net		60,604		57,898
		Proceeds from DOE Damages Claim, Net		-		163,300
		Deferral of DOE Proceeds		-		(163,300)
		Other		(21,617)		(7,574)
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		(328,299)		(182,221)
		Fuel, Materials and Supplies		68,172		75,041
		Taxes Receivable/Accrued, Net		272,021		(59,840)
		Accounts Payable		(59,496)		53,905
		Other Current Assets and Liabilities, Net		34,179		11,282
Net Cash Flows Provided by Operating Activities				481,815		493,796

Investing Activities:
	Investments in Property, Plant and Equipment			(362,586)		(348,691)
	Proceeds from Sales of Marketable Securities			114,730		128,505
	Purchases of Marketable Securities			(116,735)		(132,605)
	Other Investing Activities			66		1,637
Net Cash Flows Used in Investing Activities				(364,525)		(351,154)

Financing Activities:
	Cash Dividends on Common Shares			(132,433)		(118,460)
	Cash Dividends on Preferred Stock			(1,879)		(1,879)
	Decrease in Notes Payable			(399,575)		(299,500)
	Issuance of Long-Term Debt			450,000		400,000
	Retirements of Long-Term Debt			-		(75,000)
	Other Financing Activities			(1,079)		(2,017)
Net Cash Flows Used in Financing Activities				(84,966)		(96,856)
Net Increase in Cash and Cash Equivalents				32,324		45,786
Cash and Cash Equivalents - Beginning of Period				38,703		43,364
Cash and Cash Equivalents - End of Period			$	71,027	$	89,150

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

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

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

2013

Operating Activities:

Net Income
$
367,083

$
403,032

Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:

Depreciation

303,014

314,530

Deferred Income Taxes

133,149

256,294

Pension, SERP and PBOP Expense

47,558

97,671

Pension and PBOP Contributions

(40,640)

(122,826)

Regulatory Over/(Under) Recoveries, Net

164,388

(4,793)

Amortization of Regulatory Assets, Net

54,356

108,623

Amortization of Rate Reduction Bonds

-

42,581

Proceeds from DOE Damages Claim, Net

125,658

-

Other

(9,359)

19,932

Changes in Current Assets and Liabilities:

Receivables and Unbilled Revenues, Net

(57,570)

(101,229)

Fuel, Materials and Supplies

26,633

10,964

Taxes Receivable/Accrued, Net

(62,900)

(58,350)

Accounts Payable

(112,954)

(127,379)

Other Current Assets and Liabilities, Net

(41,753)

(70,026)
Net Cash Flows Provided by Operating Activities

896,663

769,024

Investing Activities:

Investments in Property, Plant and Equipment

(724,043)

(700,252)

Proceeds from Sales of Marketable Securities

256,309

342,251

Purchases of Marketable Securities

(257,168)

(424,096)

Decrease in Special Deposits

2,894

65,121

Other Investing Activities

579

(843)
Net Cash Flows Used in Investing Activities

(721,429)

(717,819)

Financing Activities:

Cash Dividends on Common Shares

(237,161)

(232,068)

Cash Dividends on Preferred Stock

(3,759)

(3,922)

Decrease in Short-Term Debt

(213,000)

(720,500)

Issuance of Long-Term Debt

650,000

1,350,000

Retirements of Long-Term Debt

(376,650)

(360,635)

Retirements of Rate Reduction Bonds

-

(82,139)

Other Financing Activities

(3,932)

(11,634)
Net Cash Flows Used in Financing Activities

(184,502)

(60,898)
Net Decrease in Cash and Cash Equivalents

(9,268)

(9,693)
Cash and Cash Equivalents - Beginning of Period

43,364

45,748
Cash and Cash Equivalents - End of Period
$
34,096

$
36,055

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


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


			March 31,		December 31,
(Thousands of Dollars)			2015		2014

ASSETS

Current Assets:
		Cash	$	16,818	$	2,356
		Receivables, Net		449,506		355,140
		Accounts Receivable from Affiliated Companies		27,618		16,757
		Unbilled Revenues		113,498		102,137
		Taxes Receivable		-		116,148
		Regulatory Assets		209,628		220,344
		Materials and Supplies		48,135		46,664
		Prepayments and Other Current Assets		51,074		37,822
Total Current Assets				916,277		897,368

Property, Plant and Equipment, Net				6,874,891		6,809,664

Deferred Debits and Other Assets:
		Regulatory Assets		1,454,150		1,475,508
		Other Long-Term Assets		171,085		177,568
Total Deferred Debits and Other Assets				1,625,235		1,653,076

Total Assets			$	9,416,403	$	9,360,108

LIABILITIES AND CAPITALIZATION

Current Liabilities:
	Notes Payable to ES Parent		$	190,100	$	133,400
	Long-Term Debt - Current Portion			162,000		162,000
	Accounts Payable			230,175		272,971
	Accounts Payable to Affiliated Companies			67,063		65,594
	Obligations to Third Party Suppliers			81,820		73,624
	Regulatory Liabilities			84,127		124,722
	Derivative Liabilities			88,218		88,459
	Other Current Liabilities			207,843		153,420
Total Current Liabilities				1,111,346		1,074,190

Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			1,652,415		1,642,805
	Regulatory Liabilities			82,110		81,298
	Derivative Liabilities			395,038		406,199
	Accrued Pension, SERP and PBOP			272,292		273,854
	Other Long-Term Liabilities			150,396		148,844
Total Deferred Credits and Other Liabilities				2,552,251		2,553,000

Capitalization:
	Long-Term Debt			2,680,123		2,679,951

	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		1,805,626		1,804,869
		Retained Earnings		1,091,321		1,072,477
		Accumulated Other Comprehensive Loss		(816)		(931)
	Common Stockholder's Equity			2,956,483		2,936,767
Total Capitalization				5,752,806		5,732,918

Total Liabilities and Capitalization			$	9,416,403	$	9,360,108

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

THE CONNECTICUT LIGHT AND POWER COMPANY

CONDENSED BALANCE SHEETS

(Unaudited)

June 30,

December 31,
(Thousands of Dollars)
2014

2013

ASSETS

Current Assets:

Cash
$
10,486

$
7,237

Receivables, Net

359,636

319,670

Accounts Receivable from Affiliated Companies

85,134

13,777

Unbilled Revenues

95,491

92,401

Regulatory Assets

109,951

150,943

Materials and Supplies

49,525

54,606

Prepayments and Other Current Assets

56,238

53,082
Total Current Assets

766,461

691,716

Property, Plant and Equipment, Net

6,592,833

6,451,259

Deferred Debits and Other Assets:

Regulatory Assets

1,392,529

1,663,147

Other Long-Term Assets

196,935

174,380
Total Deferred Debits and Other Assets

1,589,464

1,837,527

Total Assets
$
8,948,758

$
8,980,502

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


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


			For the Three Months Ended March 31,
(Thousands of Dollars)			2015		2014

Operating Revenues			$	804,917	$	734,614

Operating Expenses:
	Purchased Power and Transmission			333,619		281,381
	Operations and Maintenance			117,357		109,514
	Depreciation			52,902		46,130
	Amortization of Regulatory Assets, Net			48,306		29,931
	Energy Efficiency Programs			42,807		42,694
	Taxes Other Than Income Taxes			68,080		66,953
		Total Operating Expenses		663,071		576,603
Operating Income				141,846		158,011

Interest Expense:
	Interest on Long-Term Debt			33,482		32,908
	Other Interest			3,142		1,335
		Interest Expense		36,624		34,243
Other Income, Net				2,159		1,072
Income Before Income Tax Expense				107,381		124,840
Income Tax Expense				38,147		45,541
Net Income			$	69,234	$	79,299



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





CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

Net Income			$	69,234	$	79,299
Other Comprehensive Income, Net of Tax:
	Qualified Cash Flow Hedging Instruments			111		111
	Changes in Unrealized Gains on Other Securities			4		8
Other Comprehensive Income, Net of Tax				115		119
Comprehensive Income			$	69,349	$	79,418



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

THE CONNECTICUT LIGHT AND POWER COMPANY

CONDENSED BALANCE SHEETS

(Unaudited)

June 30,

December 31,
(Thousands of Dollars)
2014

2013

LIABILITIES AND CAPITALIZATION

Current Liabilities:

Notes Payable to NU Parent
$
6,400

$
287,300

Long-Term Debt - Current Portion

312,000

150,000

Accounts Payable

189,171

201,047

Accounts Payable to Affiliated Companies

44,031

56,531

Obligations to Third Party Suppliers

59,312

73,914

Accrued Taxes

52,900

37,186

Regulatory Liabilities

143,457

93,961

Derivative Liabilities

85,611

92,233

Other Current Liabilities

94,204

97,530
Total Current Liabilities

987,086

1,089,702

Deferred Credits and Other Liabilities:

Accumulated Deferred Income Taxes

1,610,662

1,510,586

Regulatory Liabilities

86,677

93,757

Derivative Liabilities

445,342

617,072

Accrued Pension, SERP and PBOP

66,543

95,895

Other Long-Term Liabilities

154,001

163,588
Total Deferred Credits and Other Liabilities

2,363,225

2,480,898

Capitalization:

Long-Term Debt

2,679,591

2,591,208

Preferred Stock Not Subject to Mandatory Redemption

116,200

116,200

Common Stockholder's Equity:

Common Stock

60,352

60,352

Capital Surplus, Paid In

1,753,668

1,682,047

Retained Earnings

989,786

961,482

Accumulated Other Comprehensive Loss

(1,150)

(1,387)

Common Stockholder's Equity

2,802,656

2,702,494
Total Capitalization

5,598,447

5,409,902

Total Liabilities and Capitalization
$
8,948,758

$
8,980,502

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


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


			For the Three Months Ended March 31,
(Thousands of Dollars)			2015		2014

Operating Activities:
	Net Income		$	69,234	$	79,299
	Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
		Depreciation		52,902		46,130
		Deferred Income Taxes		19,340		59,334
		Pension, SERP and PBOP Expense, Net of PBOP Contributions		3,883		4,086
		Regulatory Underrecoveries, Net		(67,393)		(40,399)
		Amortization of Regulatory Assets, Net		48,306		29,931
		Other		2,322		4,536
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		(124,969)		(82,833)
		Taxes Receivable/Accrued, Net		158,163		7,015
		Accounts Payable		(20,194)		(2,872)
		Other Current Assets and Liabilities, Net		(7,727)		(8,730)
Net Cash Flows Provided by Operating Activities				133,867		95,497

Investing Activities:
	Investments in Property, Plant and Equipment			(127,631)		(107,993)
	Other Investing Activities			1,981		1,027
Net Cash Flows Used in Investing Activities				(125,650)		(106,966)

Financing Activities:
	Cash Dividends on Common Stock			(49,000)		(42,800)
	Cash Dividends on Preferred Stock			(1,390)		(1,390)
	Increase in Notes Payable to ES Parent			56,700		64,300
	Other Financing Activities			(65)		(203)
Net Cash Flows Provided by Financing Activities				6,245		19,907
Net Increase in Cash				14,462		8,438
Cash - Beginning of Period				2,356		7,237
Cash - End of Period			$	16,818	$	15,675

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

THE CONNECTICUT LIGHT AND POWER COMPANY

CONDENSED STATEMENTS OF INCOME

(Unaudited)

For the Three Months Ended June 30,

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

2013

2014

2013

Operating Revenues
$
587,324

$
569,329

$
1,321,938

$
1,193,425

Operating Expenses:

Purchased Power and Transmission

199,785

184,854

481,165

414,113

Operations and Maintenance

131,762

123,760

241,276

232,655

Depreciation

46,581

45,122

92,712

87,570

Amortization of Regulatory Assets, Net

19,615

463

49,546

11,249

Energy Efficiency Programs

35,296

20,854

77,991

43,668

Taxes Other Than Income Taxes

62,159

57,506

129,111

117,697

Total Operating Expenses

495,198

432,559

1,071,801

906,952
Operating Income

92,126

136,770

250,137

286,473

Interest Expense:

Interest on Long-Term Debt

34,639

32,683

67,548

65,318

Other Interest

2,831

1,301

4,165

(1,640)

Interest Expense

37,470

33,984

71,713

63,678
Other Income, Net

3,130

2,897

4,202

7,084
Income Before Income Tax Expense

57,786

105,683

182,626

229,879
Income Tax Expense

20,401

37,826

65,942

77,014
Net Income
$
37,385

$
67,857

$
116,684

$
152,865

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

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

Net Income
$
37,385

$
67,857

$
116,684

$
152,865
Other Comprehensive Income, Net of Tax:

Qualified Cash Flow Hedging Instruments

111

111

222

222

Changes in Unrealized Gains/(Losses) on Other Securities

7

(20)

15

(26)
Other Comprehensive Income, Net of Tax

118

91

237

196
Comprehensive Income
$
37,503

$
67,948

$
116,921

$
153,061

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


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


			March 31,		December 31,
(Thousands of Dollars)			2015		2014

ASSETS

Current Assets:
		Cash and Cash Equivalents	$	17,897	$	12,773
		Receivables, Net		317,410		234,481
		Accounts Receivable from Affiliated Companies		8,372		40,353
		Unbilled Revenues		29,228		29,741
		Taxes Receivable		63,652		144,601
		Materials and Supplies		87,683		74,179
		Regulatory Assets		309,547		198,710
		Prepayments and Other Current Assets		7,885		10,815
Total Current Assets				841,674		745,653

Property, Plant and Equipment, Net				5,364,311		5,335,436

Deferred Debits and Other Assets:
		Regulatory Assets		1,178,738		1,179,100
		Other Long-Term Assets		55,839		73,051
Total Deferred Debits and Other Assets				1,234,577		1,252,151

Total Assets			$	7,440,562	$	7,333,240

LIABILITIES AND CAPITALIZATION

Current Liabilities:
	Notes Payable		$	215,500	$	302,000
	Long-Term Debt - Current Portion			4,700		4,700
	Accounts Payable			233,852		217,311
	Accounts Payable to Affiliated Companies			127,904		63,517
	Obligations to Third Party Suppliers			63,336		34,824
	Renewable Portfolio Standards Compliance Obligations			55,853		35,698
	Accumulated Deferred Income Taxes			111,288		55,136
	Regulatory Liabilities			24,605		49,611
	Other Current Liabilities			116,128		115,991
Total Current Liabilities				953,166		878,788

Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			1,530,972		1,527,667
	Regulatory Liabilities			268,122		262,738
	Accrued Pension, SERP and PBOP			228,411		235,529
	Other Long-Term Liabilities			126,006		129,279
Total Deferred Credits and Other Liabilities				2,153,511		2,155,213

Capitalization:
	Long-Term Debt			1,792,717		1,792,712

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

	Common Stockholder's Equity:
		Common Stock		-		-
		Capital Surplus, Paid In		995,378		994,130
		Retained Earnings		1,502,528		1,468,955
		Accumulated Other Comprehensive Income		262		442
	Common Stockholder's Equity			2,498,168		2,463,527
Total Capitalization				4,333,885		4,299,239

Total Liabilities and Capitalization			$	7,440,562	$	7,333,240

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


THE CONNECTICUT LIGHT AND POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
NSTAR ELECTRIC COMPANY AND SUBSIDIARY				NSTAR ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME				CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)	(Unaudited)			(Unaudited)


		For the Six Months Ended June 30,				For the Three Months Ended March 31,
(Thousands of Dollars)	(Thousands of Dollars)	2014	2013	(Thousands of Dollars)		2015		2014

Operating Revenues				Operating Revenues		$	766,808	$	666,188

Operating Expenses:				Operating Expenses:
				Purchased Power and Transmission			401,867		319,082
				Operations and Maintenance			75,824		85,924
				Depreciation			48,768		46,626
				Amortization of Regulatory Assets/(Liabilities), Net			(5,565)		15,664
				Energy Efficiency Programs			55,417		48,329
				Taxes Other Than Income Taxes			30,962		32,151
					Total Operating Expenses		607,273		547,776
Operating Income				Operating Income			159,535		118,412

Interest Expense:				Interest Expense:
				Interest on Long-Term Debt			18,645		20,756
				Other Interest			1,801		304
					Interest Expense		20,446		21,060
Other Income/(Loss), Net				Other Income/(Loss), Net			602		(31)
Income Before Income Tax Expense				Income Before Income Tax Expense			139,691		97,321
Income Tax Expense				Income Tax Expense			56,130		39,234
Net Income				Net Income		$	83,561	$	58,087



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





CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME				CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)				(Unaudited)

Net Income				Net Income		$	83,561	$	58,087
Other Comprehensive Income/(Loss), Net of Tax:				Other Comprehensive Income/(Loss), Net of Tax:
				Changes in Funded Status of SERP Benefit Plan			(180)		-
Other Comprehensive Income/(Loss), Net of Tax				Other Comprehensive Income/(Loss), Net of Tax			(180)		-
Comprehensive Income				Comprehensive Income		$	83,381	$	58,087



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

Operating Activities:

Net Income
$
116,684

$
152,865

Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:

92,712

87,570

Depreciation

Deferred Income Taxes

43,253

99,045

Pension, SERP and PBOP Expense, Net of PBOP Contributions

5,973

13,826

Regulatory Over/(Under) Recoveries, Net

18,156

(36,902)

Amortization of Regulatory Assets, Net

49,546

11,249

Proceeds from DOE Damages Claim

65,370

-

Other

(3,428)

(13,476)

Changes in Current Assets and Liabilities:

Receivables and Unbilled Revenues, Net

(129,209)

(33,976)

Taxes Receivable/Accrued, Net

27,679

(14,081)

Accounts Payable

(26,995)

(95,487)

Other Current Assets and Liabilities, Net

15,705

7,548
Net Cash Flows Provided by Operating Activities

275,446

178,181

Investing Activities:

Investments in Property, Plant and Equipment

(221,365)

(184,875)

Other Investing Activities

1,575

884
Net Cash Flows Used in Investing Activities

(219,790)

(183,991)

Financing Activities:

Cash Dividends on Common Stock

(85,600)

(76,000)

Cash Dividends on Preferred Stock

(2,779)

(2,779)

Issuance of Long Term Debt

250,000

400,000

Decrease in Notes Payable to NU Parent

(280,900)

(215,800)

Capital Contribution from NU Parent

70,000

-

Decrease in Short-Term Debt

-

(89,000)

Other Financing Activities

(3,128)

(6,345)
Net Cash Flows (Used in)/Provided by Financing Activities

(52,407)

10,076
Net Increase in Cash

3,249

4,266
Cash - Beginning of Period

7,237

1
Cash - End of Period
$
10,486

$
4,267

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

NSTAR ELECTRIC COMPANY AND SUBSIDIARY

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

June 30,

December 31,
(Thousands of Dollars)
2014

2013

ASSETS

Current Assets:

Cash and Cash Equivalents
$
12,975

$
8,021

Receivables, Net

230,039

209,711

Accounts Receivable from Affiliated Companies

-

27,264

Unbilled Revenues

40,514

41,368

Materials and Supplies

51,635

44,236

Regulatory Assets

178,640

204,144

Prepayments and Other Current Assets

1,012

36,710
Total Current Assets

514,815

571,454

Property, Plant and Equipment, Net

5,147,239

5,043,887

Deferred Debits and Other Assets:

Regulatory Assets

1,020,990

1,235,156

Other Long-Term Assets

64,963

60,624
Total Deferred Debits and Other Assets

1,085,953

1,295,780

Total Assets
$
6,748,007

$
6,911,121

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


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


			For the Three Months Ended March 31,
(Thousands of Dollars)			2015		2014

Operating Activities:
	Net Income		$	83,561	$	58,087
	Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
		Depreciation		48,768		46,626
		Deferred Income Taxes		41,297		1,585
		Pension, SERP and PBOP Expense, Net of Contributions		1,164		(4,908)
		Regulatory Over/(Under) Recoveries, Net		(103,142)		6,423
		Amortization of Regulatory Assets/(Liabilities), Net		(5,565)		15,664
		Bad Debt Expense		8,049		6,096
		Other		(21,885)		(15,538)
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		(90,465)		(14,348)
		Materials and Supplies		(13,504)		(3,606)
		Taxes Receivable/Accrued, Net		96,319		21,504
		Accounts Payable		29,210		86,309
		Accounts Receivable from/Payable to Affiliates, Net		96,368		(43,654)
		Other Current Assets and Liabilities, Net		51,157		31,112
Net Cash Flows Provided by Operating Activities				221,332		191,352

Investing Activities:
	Investments in Property, Plant and Equipment			(79,776)		(94,957)
	Other Investing Activities			53		(489)
Net Cash Flows Used in Investing Activities				(79,723)		(95,446)

Financing Activities:
	Cash Dividends on Common Stock			(49,500)		(253,000)
	Cash Dividends on Preferred Stock			(490)		(490)
	Decrease in Notes Payable			(86,500)		(103,500)
	Issuance of Long-Term Debt			-		300,000
	Other Financing Activities			5		(4,902)
Net Cash Flows Used in Financing Activities				(136,485)		(61,892)
Net Increase in Cash and Cash Equivalents				5,124		34,014
Cash and Cash Equivalents - Beginning of Period				12,773		8,021
Cash and Cash Equivalents - End of Period			$	17,897	$	42,035



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


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


			June 30,		December 31,				March 31,		December 31,
(Thousands of Dollars)	(Thousands of Dollars)		2014		2013		(Thousands of Dollars)		2015		2014

ASSETS							ASSETS

Current Assets:							Current Assets:
								Cash	$	5,149	$	489
								Receivables, Net		99,748		80,151
								Accounts Receivable from Affiliated Companies		9,917		3,194
								Unbilled Revenues		43,359		40,181
								Taxes Receivable		31,147		14,571
								Fuel, Materials and Supplies		113,566		148,139
								Regulatory Assets		99,994		111,705
								Prepayments and Other Current Assets		13,520		27,821
Total Current Assets							Total Current Assets			416,400		426,251

Property, Plant and Equipment, Net							Property, Plant and Equipment, Net			2,666,312		2,635,844

Deferred Debits and Other Assets:							Deferred Debits and Other Assets:
								Regulatory Assets		287,203		293,115
								Other Long-Term Assets		33,517		39,228
Total Deferred Debits and Other Assets							Total Deferred Debits and Other Assets			320,720		332,343

Total Assets							Total Assets		$	3,403,432	$	3,394,438

LIABILITIES AND CAPITALIZATION	LIABILITIES AND CAPITALIZATION						LIABILITIES AND CAPITALIZATION

Current Liabilities:	Current Liabilities:						Current Liabilities:
	Notes Payable		$	194,500	$	103,500	Notes Payable to ES Parent		$	82,000	$	90,500
	Long-Term Debt - Current Portion			4,700		301,650	Accounts Payable			62,513		93,349
	Accounts Payable			150,615		207,559	Accounts Payable to Affiliated Companies			42,670		33,734
	Accounts Payable to Affiliated Companies			69,949		75,707	Regulatory Liabilities			16,102		16,044
	Accrued Taxes			44,308		7,946	Accumulated Deferred Income Taxes			34,217		36,164
	Accumulated Deferred Income Taxes			54,434		50,128	Other Current Liabilities			39,777		38,969
	Regulatory Liabilities			89,161		53,958
	Other Current Liabilities			109,048		110,464
Total Current Liabilities	Total Current Liabilities			716,715		910,912	Total Current Liabilities			277,279		308,760

Deferred Credits and Other Liabilities:	Deferred Credits and Other Liabilities:						Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			1,377,432		1,466,835
	Regulatory Liabilities			260,480		253,108	Accumulated Deferred Income Taxes			627,450		587,292
	Accrued Pension, SERP and PBOP			150,151		118,010	Regulatory Liabilities			51,897		51,372
	Payable to Affiliated Companies			-		64,172	Accrued Pension, SERP and PBOP			91,847		93,243
	Other Long-Term Liabilities			129,837		142,214	Other Long-Term Liabilities			45,088		50,155
Total Deferred Credits and Other Liabilities	Total Deferred Credits and Other Liabilities			1,917,900		2,044,339	Total Deferred Credits and Other Liabilities			816,282		782,062

Capitalization:	Capitalization:						Capitalization:
	Long-Term Debt			1,792,702		1,499,417	Long-Term Debt			1,076,303		1,076,286

	Preferred Stock Not Subject to Mandatory Redemption			43,000		43,000	Common Stockholder's Equity:
								Common Stock		-		-
	Common Stockholder's Equity:							Capital Surplus, Paid In		748,634		748,240
		Common Stock		-		-		Retained Earnings		492,004		486,459
		Capital Surplus, Paid In		992,625		992,625		Accumulated Other Comprehensive Loss		(7,070)		(7,369)
		Retained Earnings		1,285,065		1,420,828	Common Stockholder's Equity			1,233,568		1,227,330
	Common Stockholder's Equity			2,277,690		2,413,453
Total Capitalization	Total Capitalization			4,113,392		3,955,870	Total Capitalization			2,309,871		2,303,616

Total Liabilities and Capitalization	Total Liabilities and Capitalization		$	6,748,007	$	6,911,121	Total Liabilities and Capitalization		$	3,403,432	$	3,394,438

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


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


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


			For the Three Months Ended June 30,				For the Six Months Ended June 30,						For the Three Months Ended March 31,
(Thousands of Dollars)	(Thousands of Dollars)		2014		2013			2014		2013	(Thousands of Dollars)		2015		2014

Operating Revenues	Operating Revenues		$	561,513	$	570,420	$	1,227,701	$	1,162,677	Operating Revenues		$	284,847	$	299,833

Operating Expenses:	Operating Expenses:										Operating Expenses:
	Purchased Power and Transmission			242,907		189,843		561,989		403,896	Purchased Power, Fuel and Transmission			99,579		115,246
	Operations and Maintenance			78,981		87,891		164,905		180,192	Operations and Maintenance			58,428		62,212
	Depreciation			46,915		45,441		93,540		90,882	Depreciation			25,646		24,215
	Amortization of Regulatory Assets/(Liabilities), Net			(1,517)		53,554		14,147		100,548	Amortization of Regulatory Assets, Net			15,132		12,562
	Amortization of Rate Reduction Bonds			-		-		-		15,054	Energy Efficiency Programs			3,772		3,839
	Energy Efficiency Programs			40,255		50,679		88,584		102,382	Taxes Other Than Income Taxes			19,079		17,715
	Taxes Other Than Income Taxes			32,458		30,491		64,610		62,665		Total Operating Expenses		221,636		235,789
		Total Operating Expenses		439,999		457,899		987,775		955,619
Operating Income	Operating Income			121,514		112,521		239,926		207,058	Operating Income			63,211		64,044

Interest Expense:	Interest Expense:										Interest Expense:
	Interest on Long-Term Debt			19,732		19,809		40,489		39,401	Interest on Long-Term Debt			11,399		11,526
	Other Interest			960		(2,620)		1,263		(6,288)	Other Interest			(127)		445
		Interest Expense		20,692		17,189		41,752		33,113		Interest Expense		11,272		11,971
Other Income/(Loss), Net				(246)		375		(277)		1,149
Other Income, Net											Other Income, Net			382		265
Income Before Income Tax Expense	Income Before Income Tax Expense			100,576		95,707		197,897		175,094	Income Before Income Tax Expense			52,321		52,338
Income Tax Expense	Income Tax Expense			40,447		37,676		79,681		68,941	Income Tax Expense			20,276		19,700
Net Income	Net Income		$	60,129	$	58,031	$	118,216	$	106,153	Net Income		$	32,045	$	32,638



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





CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME											CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)											(Unaudited)

Net Income											Net Income		$	32,045	$	32,638
Other Comprehensive Income, Net of Tax:											Other Comprehensive Income, Net of Tax:
											Qualified Cash Flow Hedging Instruments			291		290
											Changes in Unrealized Gains on Other Securities			8		14
Other Comprehensive Income, Net of Tax											Other Comprehensive Income, Net of Tax			299		304
Comprehensive Income											Comprehensive Income		$	32,344	$	32,942



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

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

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

2013


Operating Activities:
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY							PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS							CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)							(Unaudited)
	Net Income		$	118,216	$	106,153
	Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities
		Depreciation		93,540		90,882			For the Three Months Ended March 31,
(Thousands of Dollars)							(Thousands of Dollars)		2015		2014
		Deferred Income Taxes		(21,724)		28,750
		Pension and PBOP Expense, Net of Contributions		(8,281)		(5,139)
Operating Activities:							Operating Activities:
		Regulatory Over/(Under) Recoveries, Net		63,955		(33,901)	Net Income		$	32,045	$	32,638
		Amortization of Regulatory Assets, Net		14,147		100,548	Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
		Amortization of Rate Reduction Bonds		-		15,054		Depreciation		25,646		24,215
		Proceeds from DOE Damages Claim		29,113		-		Deferred Income Taxes		38,767		33,667
		Bad Debt Expense		12,272		11,307		Regulatory Over/(Under) Recoveries, Net		(288)		6,827
		Other		(29,142)		(47,574)		Amortization of Regulatory Assets, Net		15,132		12,562
	Changes in Current Assets and Liabilities:							Other		2,999		4,660
		Receivables and Unbilled Revenues, Net		(31,746)		(60,174)	Changes in Current Assets and Liabilities:
		Materials and Supplies		(7,399)		3,294		Receivables and Unbilled Revenues, Net		(31,556)		(14,268)
		Taxes Receivable/Accrued, Net		65,692		(39,813)		Fuel, Materials and Supplies		34,572		34,326
		Accounts Payable		(21,511)		(8,686)		Taxes Receivable/Accrued, Net		(16,576)		(30,254)
		Accounts Receivable from/Payable to Affiliates, Net		107,363		(57,369)		Accounts Payable		(4,285)		3,403
		Other Current Assets and Liabilities, Net		3,158		(11,702)		Other Current Assets and Liabilities, Net		17,468		21,505
Net Cash Flows Provided by Operating Activities	Net Cash Flows Provided by Operating Activities			387,653		91,630	Net Cash Flows Provided by Operating Activities			113,924		129,281

Investing Activities:	Investing Activities:						Investing Activities:
	Investments in Property, Plant and Equipment			(213,508)		(207,380)	Investments in Property, Plant and Equipment			(71,905)		(61,864)
	Decrease in Special Deposits			581		38,429	Other Investing Activities			(2,277)		(76)
	Other Investing Activities			(5)		77
Net Cash Flows Used in Investing Activities	Net Cash Flows Used in Investing Activities			(212,932)		(168,874)	Net Cash Flows Used in Investing Activities			(74,182)		(61,940)

Financing Activities:	Financing Activities:						Financing Activities:
	Cash Dividends on Common Stock			(253,000)		(56,000)	Cash Dividends on Common Stock			(26,500)		(16,500)
	Cash Dividends on Preferred Stock			(980)		(1,143)	Decrease in Notes Payable to ES Parent			(8,500)		(46,600)
	Increase/(Decrease) in Notes Payable			91,000		(23,000)	Other Financing Activities			(82)		(87)
	Issuance of Long-Term Debt			300,000		200,000
	Retirements of Long-Term Debt			(301,650)		(1,650)
	Retirements of Rate Reduction Bonds			-		(43,493)
	Other Financing Activities			(5,137)		-
Net Cash Flows (Used in)/Provided by Financing Activities				(169,767)		74,714
Net Increase/(Decrease) in Cash and Cash Equivalents				4,954		(2,530)
Cash and Cash Equivalents - Beginning of Period				8,021		13,695
Cash and Cash Equivalents - End of Period			$	12,975	$	11,165
Net Cash Flows Used in Financing Activities							Net Cash Flows Used in Financing Activities			(35,082)		(63,187)
Net Increase in Cash							Net Increase in Cash			4,660		4,154
Cash - Beginning of Period							Cash - Beginning of Period			489		130
Cash - End of Period							Cash - End of Period		$	5,149	$	4,284



The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.	The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.						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
WESTERN MASSACHUSETTS ELECTRIC COMPANY						WESTERN MASSACHUSETTS ELECTRIC COMPANY
CONDENSED BALANCE SHEETS						CONDENSED BALANCE SHEETS
(Unaudited)	(Unaudited)					(Unaudited)


		June 30,		December 31,				March 31,		December 31,
(Thousands of Dollars)	(Thousands of Dollars)	2014		2013		(Thousands of Dollars)		2015		2014

ASSETS	ASSETS					ASSETS

Current Assets:	Current Assets:					Current Assets:
	Cash	$	337	$	130		Cash	$	2,045	$	-
	Receivables, Net		69,646		76,331		Receivables, Net		72,366		51,066
	Accounts Receivable from Affiliated Companies		54		90		Accounts Receivable from Affiliated Companies		8,726		7,851
	Unbilled Revenues		36,971		38,344		Unbilled Revenues		18,186		15,146
	Taxes Receivable		45,957		2,180		Taxes Receivable		18,062		18,126
	Fuel, Materials and Supplies		120,723		128,736		Regulatory Assets		66,706		51,923
	Regulatory Assets		95,270		92,194		Marketable Securities		33,183		28,658
	Prepayments and Other Current Assets		21,770		21,920		Prepayments and Other Current Assets		6,431		7,607
Total Current Assets	Total Current Assets		390,728		359,925	Total Current Assets			225,705		180,377

Property, Plant and Equipment, Net	Property, Plant and Equipment, Net		2,519,921		2,467,556	Property, Plant and Equipment, Net			1,483,895		1,461,321

Deferred Debits and Other Assets:	Deferred Debits and Other Assets:					Deferred Debits and Other Assets:
	Regulatory Assets		187,592		219,346		Regulatory Assets		137,894		146,307
	Other Long-Term Assets		53,779		39,891		Marketable Securities		25,027		29,452
							Other Long-Term Assets		22,726		22,018
Total Deferred Debits and Other Assets	Total Deferred Debits and Other Assets		241,371		259,237	Total Deferred Debits and Other Assets			185,647		197,777

Total Assets						Total Assets		$	1,895,247	$	1,839,475

LIABILITIES AND CAPITALIZATION						LIABILITIES AND CAPITALIZATION

Current Liabilities:						Current Liabilities:
						Notes Payable to ES Parent		$	70,500	$	21,400
						Long-Term Debt - Current Portion			50,000		50,000
						Accounts Payable			40,665		53,732
Total Assets		$	3,152,020	$	3,086,718
						Accounts Payable to Affiliated Companies			21,634		14,328
						Regulatory Liabilities			22,289		22,486
						Accumulated Deferred Income Taxes			24,607		18,089
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
						Other Current Liabilities			22,958		24,080
Total Current Liabilities						Total Current Liabilities			252,653		204,115

Deferred Credits and Other Liabilities:						Deferred Credits and Other Liabilities:
						Accumulated Deferred Income Taxes			419,043		416,822
						Regulatory Liabilities			12,673		10,835
						Accrued Pension, SERP and PBOP			16,505		17,705
						Other Long-Term Liabilities			34,182		33,747
Total Deferred Credits and Other Liabilities						Total Deferred Credits and Other Liabilities			482,403		479,109

Capitalization:						Capitalization:
						Long-Term Debt			578,239		578,471

						Common Stockholder's Equity:
							Common Stock		10,866		10,866
							Capital Surplus, Paid In		391,398		391,256
							Retained Earnings		182,778		178,834
							Accumulated Other Comprehensive Loss		(3,090)		(3,176)
						Common Stockholder's Equity			581,952		577,780
Total Capitalization						Total Capitalization			1,160,191		1,156,251

Total Liabilities and Capitalization						Total Liabilities and Capitalization		$	1,895,247	$	1,839,475

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

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

June 30,

December 31,
(Thousands of Dollars)
2014

2013

LIABILITIES AND CAPITALIZATION

Current Liabilities:

Notes Payable to NU Parent
$
95,000

$
86,500

Long-Term Debt - Current Portion

50,000

50,000

Accounts Payable

58,910

82,920

Accounts Payable to Affiliated Companies

18,760

22,040

Regulatory Liabilities

36,627

20,643

Accumulated Deferred Income Taxes

25,397

28,596

Other Current Liabilities

35,440

51,729
Total Current Liabilities

320,134

342,428

Deferred Credits and Other Liabilities:

Accumulated Deferred Income Taxes

563,291

500,166

Regulatory Liabilities

50,843

51,723

Accrued SERP and PBOP

15,055

15,272

Other Long-Term Liabilities

46,598

46,247
Total Deferred Credits and Other Liabilities

675,787

613,408

Capitalization:

Long-Term Debt

999,157

999,006

Common Stockholder's Equity:

Common Stock

-

-

Capital Surplus, Paid In

702,652

701,911

Retained Earnings

462,233

438,515

Accumulated Other Comprehensive Loss

(7,943)

(8,550)

Common Stockholder's Equity

1,156,942

1,131,876
Total Capitalization

2,156,099

2,130,882

Total Liabilities and Capitalization
$
3,152,020

$
3,086,718

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


WESTERN MASSACHUSETTS ELECTRIC COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)


			For the Three Months Ended March 31,
(Thousands of Dollars)			2015		2014

Operating Revenues			$	152,864	$	137,409

Operating Expenses:
	Purchased Power and Transmission			69,661		49,431
	Operations and Maintenance			19,784		22,579
	Depreciation			10,375		10,321
	Amortization of Regulatory Assets, Net			3,927		399
	Energy Efficiency Programs			11,075		11,865
	Taxes Other Than Income Taxes			9,437		8,082
		Total Operating Expenses		124,259		102,677
Operating Income				28,605		34,732

Interest Expense:
	Interest on Long-Term Debt			6,045		6,062
	Other Interest			778		(416)
		Interest Expense		6,823		5,646
Other Income, Net				575		574
Income Before Income Tax Expense				22,357		29,660
Income Tax Expense				9,113		11,558
Net Income			$	13,244	$	18,102



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





CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

Net Income			$	13,244	$	18,102
Other Comprehensive Income, Net of Tax:
	Qualified Cash Flow Hedging Instruments			85		85
	Changes in Unrealized Gains on Other Securities			1		2
Other Comprehensive Income, Net of Tax				86		87
Comprehensive Income			$	13,330	$	18,189



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

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

For the Three Months Ended June 30,

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

2013

2014

2013

Operating Revenues
$
211,626

$
216,113

$
511,458

$
489,942

Operating Expenses:

Purchased Power, Fuel and Transmission

68,349

50,073

183,595

151,097

Operations and Maintenance

70,249

62,400

132,462

122,129

Depreciation

24,464

22,947

48,679

45,515

Amortization of Regulatory Assets/(Liabilities), Net

(20,393)

1,081

(7,831)

(1,969)

Amortization of Rate Reduction Bonds

-

4,991

-

19,748

Energy Efficiency Programs

3,292

3,376

7,131

7,046

Taxes Other Than Income Taxes

16,635

16,918

34,348

33,932

Total Operating Expenses

162,596

161,786

398,384

377,498
Operating Income

49,030

54,327

113,074

112,444

Interest Expense:

Interest on Long-Term Debt

11,390

10,811

22,916

22,606

Other Interest

(391)

337

55

709

Interest Expense

10,999

11,148

22,971

23,315
Other Income, Net

946

632

1,212

1,662
Income Before Income Tax Expense

38,977

43,811

91,315

90,791
Income Tax Expense

14,897

16,617

34,597

34,602
Net Income
$
24,080

$
27,194

$
56,718

$
56,189

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

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

Net Income
$
24,080

$
27,194

$
56,718

$
56,189
Other Comprehensive Income, Net of Tax:

Qualified Cash Flow Hedging Instruments

291

291

581

582

Changes in Unrealized Gains/(Losses) on Other Securities

12

(34)

26

(45)

Changes in Funded Status of Pension, SERP and PBOP Benefit Plans

-

-

-

(3)
Other Comprehensive Income, Net of Tax

303

257

607

534
Comprehensive Income
$
24,383

$
27,451

$
57,325

$
56,723

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


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


			For the Three Months Ended March 31,
(Thousands of Dollars)			2015		2014

Operating Activities:
	Net Income		$	13,244	$	18,102
	Adjustments to Reconcile Net Income to Net Cash Flows Provided by/(Used in) Operating Activities:
		Depreciation		10,375		10,321
		Deferred Income Taxes		12,759		14,688
		Regulatory Over/(Under) Recoveries, Net		(14,442)		5,780
		Amortization of Regulatory Assets, Net		3,927		399
		Other		(1,197)		(1,351)
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		(26,298)		34,905
		Taxes Receivable/Accrued, Net		64		(17,126)
		Accounts Payable		85		(10,516)
		Other Current Assets and Liabilities, Net		65		(8,869)
Net Cash Flows Provided by/(Used in) Operating Activities				(1,418)		46,333

Investing Activities:
	Investments in Property, Plant and Equipment			(35,899)		(30,347)
	Proceeds from Sales of Marketable Securities			23,249		34,656
	Purchases of Marketable Securities			(23,442)		(34,804)
Net Cash Flows Used in Investing Activities				(36,092)		(30,495)

Financing Activities:
	Cash Dividends on Common Stock			(9,300)		(49,000)
	Increase in Notes Payable to ES Parent			49,100		37,400
	Other Financing Activities			(245)		(11)
Net Cash Flows Provided by/(Used in) Financing Activities				39,555		(11,611)
Net Increase in Cash				2,045		4,227
Cash - Beginning of Period				-		-
Cash - End of Period			$	2,045	$	4,227


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

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

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

2013

Operating Activities:

Net Income
$
56,718

$
56,189

Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:

Depreciation

48,679

45,515

Deferred Income Taxes

61,093

25,450

Pension, SERP and PBOP Expense

3,249

14,228

Pension and PBOP Contributions

(833)

(45,721)

Regulatory Overrecoveries, Net

18,849

4,844

Amortization of Regulatory Liabilities, Net

(7,831)

(1,969)

Amortization of Rate Reduction Bonds

-

19,748

Proceeds from DOE Damages Claim

13,103

-

Other

4,386

3,123

Changes in Current Assets and Liabilities:

Receivables and Unbilled Revenues, Net

3,500

597

Fuel, Materials and Supplies

8,013

(13,289)

Taxes Receivable/Accrued, Net

(55,243)

21,584

Accounts Payable

(7,146)

26,159

Other Current Assets and Liabilities, Net

(4,166)

(17,743)
Net Cash Flows Provided by Operating Activities

142,371

138,715

Investing Activities:

Investments in Property, Plant and Equipment

(117,387)

(109,565)

(Increase)/Decrease in Special Deposits

(45)

22,039

Other Investing Activities

(56)

(13)
Net Cash Flows Used in Investing Activities

(117,488)

(87,539)

Financing Activities:

Cash Dividends on Common Stock

(33,000)

(34,000)

Increase in Notes Payable to NU Parent

8,500

118,900

Retirements of Long-Term Debt

-

(108,985)

Retirements of Rate Reduction Bonds

-

(29,294)

Other Financing Activities

(176)

(225)
Net Cash Flows Used in Financing Activities

(24,676)

(53,604)
Net Increase/(Decrease) in Cash

207

(2,428)
Cash - Beginning of Period

130

2,493
Cash - End of Period
$
337

$
65

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

WESTERN MASSACHUSETTS ELECTRIC COMPANY

CONDENSED BALANCE SHEETS

(Unaudited)

June 30,

December 31,
(Thousands of Dollars)
2014

2013

ASSETS

Current Assets:

Cash
$
1,709

$
-

Receivables, Net

49,404

49,018

Accounts Receivable from Affiliated Companies

4,445

47,607

Unbilled Revenues

15,617

16,562

Taxes Receivable

15,228

432

Regulatory Assets

36,251

43,024

Marketable Securities

19,408

26,628

Prepayments and Other Current Assets

10,730

10,479
Total Current Assets

152,792

193,750

Property, Plant and Equipment, Net

1,418,673

1,381,060

Deferred Debits and Other Assets:

Regulatory Assets

120,303

146,088

Marketable Securities

38,640

31,243

Other Long-Term Assets

50,438

40,679
Total Deferred Debits and Other Assets

209,381

218,010

Total Assets
$
1,780,846

$
1,792,820

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

WESTERN MASSACHUSETTS ELECTRIC COMPANY
CONDENSED BALANCE SHEETS
(Unaudited)

June 30,

December 31,
(Thousands of Dollars)
2014

2013

LIABILITIES AND CAPITALIZATION

Current Liabilities:

Notes Payable to NU Parent
$
15,900

$
-

Accounts Payable

28,502

62,961

Accounts Payable to Affiliated Companies

7,533

9,230

Accrued Interest

7,524

7,525

Regulatory Liabilities

44,745

19,858

Accumulated Deferred Income Taxes

57

13,098

Counterparty Deposits

188

7,688

Other Current Liabilities

16,518

20,629
Total Current Liabilities

120,967

140,989

Deferred Credits and Other Liabilities:

Accumulated Deferred Income Taxes

423,013

396,933

Regulatory Liabilities

10,317

13,873

Accrued SERP and PBOP

2,805

3,911

Other Long-Term Liabilities

39,121

28,619
Total Deferred Credits and Other Liabilities

475,256

443,336

Capitalization:

Long-Term Debt

628,932

629,389

Common Stockholder's Equity:

Common Stock

10,866

10,866

Capital Surplus, Paid In

391,035

390,743

Retained Earnings

157,134

181,014

Accumulated Other Comprehensive Loss

(3,344)

(3,517)

Common Stockholder's Equity

555,691

579,106
Total Capitalization

1,184,623

1,208,495

Total Liabilities and Capitalization
$
1,780,846

$
1,792,820

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

WESTERN MASSACHUSETTS ELECTRIC COMPANY

CONDENSED STATEMENTS OF INCOME

(Unaudited)

For the Three Months Ended June 30,

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

2013

2014

2013

Operating Revenues
$
108,289

$
115,015

$
245,698

$
239,968

Operating Expenses:

Purchased Power and Transmission

37,619

32,254

87,050

72,298

Operations and Maintenance

23,686

23,136

46,265

44,064

Depreciation

10,317

9,310

20,638

18,280

Amortization of Regulatory Assets, Net

343

685

741

814

Amortization of Rate Reduction Bonds

-

3,091

-

7,780

Energy Efficiency Programs

10,249

7,925

22,114

16,240

Taxes Other Than Income Taxes

8,396

6,206

16,479

12,494

Total Operating Expenses

90,610

82,607

193,287

171,970
Operating Income

17,679

32,408

52,411

67,998

Interest Expense:

Interest on Long-Term Debt

6,104

6,078

12,165

12,032

Other Interest

603

198

188

537

Interest Expense

6,707

6,276

12,353

12,569
Other Income, Net

594

419

1,168

1,423
Income Before Income Tax Expense

11,566

26,551

41,226

56,852
Income Tax Expense

4,548

10,137

16,106

21,836
Net Income
$
7,018

$
16,414

$
25,120

$
35,016

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

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

Net Income
$
7,018

$
16,414

$
25,120

$
35,016
Other Comprehensive Income, Net of Tax:

Qualified Cash Flow Hedging Instruments

84

84

169

169

Changes in Unrealized Gains/(Losses) on Other Securities

2

(6)

4

(8)
Other Comprehensive Income, Net of Tax

86

78

173

161
Comprehensive Income
$
7,104

$
16,492

$
25,293

$
35,177

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

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

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

2013

Operating Activities:

Net Income
$
25,120

$
35,016

Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:

Depreciation

20,638

18,280

Deferred Income Taxes

15,234

33,317

Regulatory Over/(Under) Recoveries, Net

28,115

(5,094)

Amortization of Regulatory Assets, Net

741

814

Amortization of Rate Reduction Bonds

-

7,780

Proceeds from DOE Damages Claim

18,073

-

Other

1,462

572

Changes in Current Assets and Liabilities:

Receivables and Unbilled Revenues, Net

44,859

(8,681)

Taxes Receivable/Accrued, Net

(19,555)

21,081

Accounts Payable

(26,494)

21,389

Other Current Assets and Liabilities, Net

(11,587)

(5,166)
Net Cash Flows Provided by Operating Activities

96,606

119,308

Investing Activities:

Investments in Property, Plant and Equipment

(61,470)

(96,051)

Proceeds from Sales of Marketable Securities

44,449

41,604

Purchases of Marketable Securities

(44,754)

(41,961)

Other Investing Activities

-

4,601
Net Cash Flows Used in Investing Activities

(61,775)

(91,807)

Financing Activities:

Cash Dividends on Common Stock

(49,000)

(20,000)

Increase in Notes Payable to NU Parent

15,900

3,300

Retirement of Rate Reduction Bonds

-

(9,352)

Other Financing Activities

(22)

(31)
Net Cash Flows Used in Financing Activities

(33,122)

(26,083)
Net Increase in Cash

1,709

1,418
Cash - Beginning of Period

-

1
Cash - End of Period
$
1,709

$
1,419

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

~~NORTHEAST UTILITIES~~EVERSOURCE ENERGY 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

NUEversource Energy is a public utility holding company primarily engaged through its wholly owned regulated utility subsidiaries in the energy delivery business. ~~NU's~~Eversource Energy's wholly owned regulated utility subsidiaries consist of CL&P, NSTAR Electric, PSNH, WMECO, Yankee Gas and NSTAR Gas. NUEversource 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.

On April 29, 2015, the Company's name was changed from Northeast Utilities to Eversource Energy. CL&P, NSTAR Electric, PSNH and WMECO operate under the brand Eversource Energy.

The unaudited condensed consolidated financial statements of ~~NU,~~Eversource, 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,~~Eversource, NSTAR Electric and PSNH and the unaudited condensed financial statements of CL&P and WMECO are herein collectively referred to as the "financial statements."

The combined notes to the financial statements have been prepared pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures included in annual financial statements prepared in accordance with GAAP have been omitted pursuant to such rules and regulations. The accompanying financial statements should be read in conjunction with the entirety of this combined Quarterly Report on Form 10-Q ~~the first quarter 2014 combined Quarterly Report on Form 10-Q~~ and the ~~2013~~2014 combined Annual Report on Form 10-K of ~~NU,~~Eversource, CL&P, NSTAR Electric, PSNH and WMECO, which ~~were~~was 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,~~Eversource's, CL&P's, NSTAR Electric's, PSNH's and WMECO's financial position as of ~~June 30, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, and the results of operations, ~~and~~ comprehensive income ~~for the three~~ and ~~six months ended June 30, 2014 and 2013, and the~~ cash flows for the ~~six~~three months ended ~~June 30, 2014~~March 31, 2015 and ~~2013.~~2014. The results of operations, ~~and~~ comprehensive income ~~for the three~~ and ~~six months ended June 30, 2014 and 2013, and the~~ cash flows for the ~~six~~three months ended ~~June 30,~~March 31, 2015 and 2014 ~~and 2013~~ are not necessarily indicative of the results expected for a full year. The demand for electricity and natural gas is affected by weather conditions, economic conditions, and consumer conservation (including company-sponsored energy efficiency programs). Electric energy sales and revenues are typically higher in the winter and summer months than in the spring and fall months. Natural gas sales and revenues are typically higher in the winter months than during other periods of the year.

NUEversource consolidates CYAPC and YAEC asbecause 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 NUEversource 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~~Eversource's utility ~~subsidiaries~~subsidiaries' distribution (including generation) and transmission businesses and NPT are subject to rate-regulation that is based on cost recovery and meets the criteria for application of accounting guidance for entities with rate-regulated operations, ~~that~~which considers the effect of regulation ~~resulting from~~on the 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~~financial 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~~Financial Accounting Standards Board (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). In April 2015, the FASB decided to propose a one-year deferral of the effective date of the ASU. Management is reviewing the requirements of the ~~new~~ASU. The ASU ~~however the ASU's impact~~ is not expected to have a material impact on the financial statements of ~~NU,~~Eversource, CL&P, NSTAR Electric, PSNH and WMECO.

C.
Provision for Uncollectible Accounts
~~NU,~~Eversource, 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 judgments and 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~~collectability from ~~individual~~ customers. Management continuously assesses the ~~collectibility~~collectability of receivables and adjusts ~~collectibility~~collectability 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 PURA allows CL&P and Yankee Gas to accelerate the recovery of accounts receivable balances attributable to qualified customers under financial or medical duress (uncollectible hardship accounts receivable) outstanding for greater than 90 days. The DPU allows WMECO to also

16

recover in rates amounts associated with certain uncollectible hardship accounts receivable. Uncollectible customer account balances, which are expected to be recovered in rates, are included in Regulatory Assets or Other Long-Term Assets.

The total provision for uncollectible accounts and for uncollectible hardship accounts, which is included in the total provision, are included in Receivables, Net on the balance sheets, ~~was~~and were as follows:

Total Provision for Uncollectible Accounts

Uncollectible Hardship
(Millions of Dollars)

As of June 30, 2014

As of December 31, 2013
(Millions of Dollars)

As of March 31, 2015

As of December 31, 2014

As of March 31, 2015

As of December 31, 2014
NU

$
197.4

$
171.3
ES
ES

$
187.4

$
175.3

$
92.3

$
91.5
CL&P

91.8

82.0
CL&P

86.6

84.3

74.5

74.0
NSTAR Electric

44.4

41.7
NSTAR Electric

43.8

40.7

-

-
PSNH

9.2

7.4
PSNH

8.1

7.7

-

-
WMECO

12.9

10.0
WMECO

10.7

9.9

6.5

6.2

D.
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 of the investments used to calculate the funded status of pension and PBOP plans and nonrecurring fair value measurements of nonfinancial assets such as goodwill and ~~AROs.~~ AROs, and is also used to estimate the fair value of preferred stock and long-term debt.

Fair Value Hierarchy: In measuring fair value, NUEversource 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. NUEversource evaluates the classification of assets and liabilities measured at fair value on a quarterly basis, and ~~NU's~~Eversource'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~~Eversource's fair value measurements are described in Note 4, "Derivative Instruments," Note 5, "Marketable Securities," and Note 9, "Fair Value of Financial Instruments," to the financial statements.

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

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

For the Three Months Ended

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

June 30, 2013

June 30, 2014

June 30, 2013
March 31, 2015

March 31, 2014
NU
$
35.2

$
33.0

$
79.6

$
71.4
ES
$
41.9

$
44.4
CL&P

30.9

29.8

66.5

61.8

33.0

35.6

Certain sales taxes are ~~also~~ collected by ~~NU's~~Eversource'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 March 31, 2015

As of March 31, 2014
ES
$
110.4

$
108.5
CL&P

42.3

36.2
NSTAR Electric

21.9

28.0
PSNH

21.7

14.4
WMECO

8.3

14.4

2217

G.
Supplemental Cash Flow Information

Non-cash investing activities include plant additions included in Accounts Payable as follows:

(Millions of Dollars)
As of June 30, 2014

As of June 30, 2013

NU
$
125.5

$
109.5

CL&P

54.0

28.3

NSTAR Electric

21.6

33.4

PSNH

14.8

15.5

WMECO

9.9

17.0

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

H.
Severance Benefits
NUFor the three months ended March 31, 2015 and 2014, Eversource recorded severance benefit ~~expenses~~expense of ~~$1.4~~$0.4 million and ~~$5.7~~$4.3 million, ~~associated~~respectively, in connection with ongoing post-merger integration and, in 2014, the partial outsourcing of information technology ~~functions and ongoing post-merger integration for the three and six months ended June 30, 2014, respectively.~~functions. As of ~~June 30, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, the severance accrual totaled ~~$9.3~~$9 million and ~~$14.7~~$10.4 million, respectively, and was included in Other Current Liabilities on the balance sheets.

2.
REGULATORY ACCOUNTING

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

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

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

As of June 30, 2014

As of December 31, 2013
As of March 31, 2015

As of December 31, 2014
(Millions of Dollars)
NU

NU
ES

ES
Benefit Costs
$
1,146.7

$
1,240.2
$
1,976.6

$
2,016.0
Derivative Liabilities

431.4

638.0

410.2

425.5
Income Taxes, Net

631.8

626.2

632.1

635.3
Storm Restoration Costs

503.9

589.6

504.8

502.8
Goodwill-related

515.7

525.9

500.2

505.4
Regulatory Tracker Mechanisms

275.1

323.4

434.5

350.5
Contractual Obligations - Yankee Companies

128.4

154.2

119.0

123.8
Buy Out Agreements for Power Contracts

56.7

70.2
Other Regulatory Assets

117.0

126.8

151.4

167.3
Total Regulatory Assets

3,806.7

4,294.5

4,728.8

4,726.6
Less: Current Portion

467.2

535.8

747.3

672.5
Total Long-Term Regulatory Assets
$
3,339.5

$
3,758.7
$
3,981.5

$
4,054.1


		As of June 30, 2014								As of December 31, 2013									As of March 31, 2015								As of December 31, 2014
				NSTAR								NSTAR									NSTAR								NSTAR
(Millions of Dollars)	(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric		PSNH		WMECO		(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric		PSNH		WMECO
Benefit Costs	Benefit Costs	$	251.9	$	323.4	$	81.6	$	46.2	$	297.7	$	496.7	$	100.6	$	57.3	Benefit Costs	$	436.7	$	505.6	$	171.2	$	83.3	$	445.4	$	515.9	$	174.3	$	85.0
Derivative Liabilities	Derivative Liabilities		424.6		6.3		-		-		630.4		7.7		-		-	Derivative Liabilities		403.3		3.5		-		-		410.9		4.5		-		-
Income Taxes, Net	Income Taxes, Net		426.2		81.4		38.0		40.8		415.5		84.0		40.3		43.7	Income Taxes, Net		438.7		83.7		36.8		31.2		437.7		83.7		38.0		35.5
Storm Restoration Costs	Storm Restoration Costs		328.0		107.2		34.7		34.0		397.8		109.3		43.7		38.8	Storm Restoration Costs		308.5		119.7		46.9		29.7		319.6		103.7		47.7		31.8
Goodwill-related	Goodwill-related		-		442.8		-		-		-		451.5		-		-	Goodwill-related		-		429.5		-		-		-		433.9		-		-
Regulatory Tracker Mechanisms	Regulatory Tracker Mechanisms		8.1		131.8		87.9		20.7		8.0		169.5		83.3		32.6	Regulatory Tracker Mechanisms		10.1		261.2		93.4		47.6		16.1		141.4		103.5		33.0
Buy Out Agreements for Power Contracts			-		52.0		4.7		-		-		64.7		5.5		-
Other Regulatory Assets	Other Regulatory Assets		63.7		54.7		36.0		14.9		64.6		55.9		38.1		16.7	Other Regulatory Assets		66.5		85.0		38.9		12.8		66.1		94.7		41.3		12.9
Total Regulatory Assets	Total Regulatory Assets		1,502.5		1,199.6		282.9		156.6		1,814.0		1,439.3		311.5		189.1	Total Regulatory Assets		1,663.8		1,488.2		387.2		204.6		1,695.8		1,377.8		404.8		198.2
Less: Current Portion	Less: Current Portion		110.0		178.6		95.3		36.3		150.9		204.1		92.2		43.0	Less: Current Portion		209.6		309.5		100.0		66.7		220.3		198.7		111.7		51.9
Total Long-Term Regulatory Assets	Total Long-Term Regulatory Assets	$	1,392.5	$	1,021.0	$	187.6	$	120.3	$	1,663.1	$	1,235.2	$	219.3	$	146.1	Total Long-Term Regulatory Assets	$	1,454.2	$	1,178.7	$	287.2	$	137.9	$	1,475.5	$	1,179.1	$	293.1	$	146.3

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

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

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

Regulatory Costs in Other Long-Term Assets: The Regulated companies had ~~$64.5~~$49.3 million ($~~3.4~~1.6 million for CL&P, ~~$33.9~~$18.3 million for NSTAR Electric, $0.4 million for PSNH and ~~$12~~$11.8 million for WMECO) and ~~$65.1~~$60.5 million ($~~7.3~~1.3 million for CL&P, ~~$33.4~~$33.2 million for NSTAR Electric, $0.9 million for PSNH, and ~~$10.1~~$11 million for WMECO) of additional regulatory costs as of ~~June 30, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, 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. The NSTAR Electric balance as of March 31, 2015 and December 31, 2014 primarily related to costs deferred in connection with the basic service bad debt adder. See Note 8E, "Commitments and Contingencies – Basic Service Bad Debt Adder," for further information.

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

As of June 30, 2014

As of December 31, 2013
(Millions of Dollars)
NU

NU
Cost of Removal
$
435.3

$
435.1
Regulatory Tracker Mechanisms

305.2

151.2
AFUDC - Transmission

67.4

68.1
Other Regulatory Liabilities

56.0

52.9
Total Regulatory Liabilities

863.9

707.3
Less: Current Portion

359.9

204.3
Total Long-Term Regulatory Liabilities
$
504.0

$
503.0


		As of June 30, 2014								As of December 31, 2013
				NSTAR								NSTAR						As of March 31, 2015		As of December 31, 2014
(Millions of Dollars)	(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric		PSNH		WMECO		ES		ES
Cost of Removal	Cost of Removal	$	22.8	$	255.7	$	48.7	$	-	$	29.1	$	250.0	$	49.7	$	-	$	452.8	$	439.9
Regulatory Tracker Mechanisms	Regulatory Tracker Mechanisms		143.2		60.2		34.8		45.1		95.6		21.9		21.6		21.1		183.3		192.3
AFUDC - Transmission	AFUDC - Transmission		54.2		4.0		-		9.2		54.7		4.1		-		9.3		67.1		67.1
Other Regulatory Liabilities	Other Regulatory Liabilities		10.0		29.8		3.9		0.7		8.4		31.1		1.0		3.4		22.9		50.8
Total Regulatory Liabilities	Total Regulatory Liabilities		230.2		349.7		87.4		55.0		187.8		307.1		72.3		33.8		726.1		750.1
Less: Current Portion	Less: Current Portion		143.5		89.2		36.6		44.7		94.0		54.0		20.6		19.9		201.2		235.0
Total Long-Term Regulatory Liabilities	Total Long-Term Regulatory Liabilities	$	86.7	$	260.5	$	50.8	$	10.3	$	93.8	$	253.1	$	51.7	$	13.9	$	524.9	$	515.1


	As of March 31, 2015								As of December 31, 2014
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric		PSNH		WMECO
Cost of Removal	$	23.1	$	263.4	$	51.3	$	2.8	$	19.7	$	258.3	$	50.3	$	1.1
Regulatory Tracker Mechanisms		77.5		22.5		13.9		22.2		122.6		20.7		14.2		22.3
AFUDC - Transmission		53.3		4.7		-		9.1		53.6		4.4		-		9.1
Other Regulatory Liabilities		12.3		2.1		2.8		0.9		10.1		28.9		2.9		0.8
Total Regulatory Liabilities		166.2		292.7		68.0		35.0		206.0		312.3		67.4		33.3
Less: Current Portion		84.1		24.6		16.1		22.3		124.7		49.6		16.0		22.5
Total Long-Term Regulatory Liabilities	$	82.1	$	268.1	$	51.9	$	12.7	$	81.3	$	262.7	$	51.4	$	10.8

2015 Regulatory Developments:As a result of ~~two~~the March 3, 2015 FERC ~~orders issued on June 19, 2014~~order in the pending ~~base~~ ROE complaint proceedings described in Note 8E, "Commitments and Contingencies – FERC Base ROE Complaints," in the second quarter of 2014, the Company recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact of these rulings. The aggregate pre-tax charge totaled $54.7 million at NU, which represented reserves of $31.4 million at CL&P, $10.3 million at NSTAR Electric, $3.8 million at PSNH and $9.2 million at WMECO. As of June 30, 2014, the cumulative reserves totaled $79.3 million at NU, $44.7 million at CL&P, $16.2 million at NSTAR Electric, $6.2 million at PSNH and $12.2 million at WMECO. As of December 31, 2013, as a result of the FERC ALJ initial decision in the third quarter of 2013, the Company had an aggregate pre-tax reserve of $24.6 million at NU, which represented reserves of $13.3 million at CL&P, $5.9 million at NSTAR Electric, $2.4 million at PSNH and $3 million at WMECO. These reserves were recorded in each electric subsidiary's respective transmission regulatory tracker mechanism and as a reduction of operating revenues.

~~As a result of awards issued to the Yankee Companies for spent nuclear fuel lawsuits against the DOE~~ described in Note 8C, "Commitments and Contingencies ~~- Contractual Obligations - Yankee Companies,~~– FERC ROE Complaints," in the ~~Yankee Companies returned the DOE Phase II Damages proceeds~~first quarter of 2015, Eversource recognized a pre-tax charge to ~~the member companies, including CL&P, NSTAR Electric, PSNH, and WMECO, for the benefit~~earnings (excluding interest) of ~~their respective customers, effective June 1, 2014. CL&P's refund obligation to customers~~$20 million, of ~~$65.4~~which $12.5 million was recorded ~~as an offset to the deferred storm restoration costs regulatory asset, as directed by PURA.~~at CL&P, $2.4 million at NSTAR ~~Electric's, PSNH's~~Electric, $1 million at PSNH, and ~~WMECO's refund obligation to customers of $29.1~~$4.1 million ~~$13.1 million and $18.1 million, respectively,~~at WMECO. The pre-tax charge was recorded as a regulatory liability ~~in each electric subsidiary's respective regulatory tracker mechanisms.~~and as a reduction of Operating Revenues.

24On March 2, 2015, the DPU approved the comprehensive settlement agreement between NSTAR Electric, NSTAR Gas and the Massachusetts Attorney General (the "Settlement") as filed with the DPU on December 31, 2014. The Settlement resolved the outstanding NSTAR Electric CPSL program filings for 2006 through 2011, the NSTAR Electric and NSTAR Gas PAM and energy efficiency-related customer billing adjustments reported in 2012, and the recovery of LBR related to NSTAR Electric's energy efficiency programs for 2008 through 2011 (11 dockets in total). As a result, NSTAR Electric and NSTAR Gas will refund a combined $44.7 million to customers. The refund was recorded as a regulatory liability as of March 31, 2015 and NSTAR Electric recognized a $21.7 million pre-tax benefit in the first quarter of 2015. For further information, see Note 8D, "Commitments and Contingencies – 2014 Comprehensive Settlement Agreement."

On January 7, 2015, the DPU issued an order concluding that NSTAR Electric had appropriately accounted for the removal of supply-related bad debt costs from base distribution rates effective January 1, 2006. The DPU ordered NSTAR Electric and the Massachusetts Attorney General to collaborate on the reconciliation of energy-related bad debt costs through 2014. During the second quarter of 2015, NSTAR Electric expects to file with the DPU to recover from customers approximately $43 million of supply-related bad debt costs. In the first quarter of 2015, as a result of the DPU order, NSTAR Electric increased its regulatory assets and reduced Operations and Maintenance expense by $24.2 million, resulting in an increase in after-tax earnings of $14.5 million. For further information, see Note 8E, "Commitments and Contingencies – Basic Service Bad Debt Adder."

PROPERTY, PLANT AND EQUIPMENT AND ACCUMULATED DEPRECIATION

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


		As of June 30, 2014		As of December 31, 2013			As of March 31, 2015		As of December 31, 2014
(Millions of Dollars)	(Millions of Dollars)	NU		NU		(Millions of Dollars)	ES		ES
Distribution - Electric	Distribution - Electric	$	12,145.0	$	11,950.2	Distribution - Electric	$	12,539.3	$	12,495.2
Distribution - Natural Gas	Distribution - Natural Gas		2,467.4		2,425.9	Distribution - Natural Gas		2,584.8		2,595.4
Transmission	Transmission		6,508.0		6,412.5	Transmission		6,959.4		6,930.7
Generation	Generation		1,167.9		1,152.3	Generation		1,172.2		1,170.9
Electric and Natural Gas Utility	Electric and Natural Gas Utility		22,288.3		21,940.9	Electric and Natural Gas Utility		23,255.7		23,192.2
Other⁽¹⁾	Other⁽¹⁾		506.5		508.7	Other⁽¹⁾		547.9		551.3
Property, Plant and Equipment, Gross	Property, Plant and Equipment, Gross		22,794.8		22,449.6	Property, Plant and Equipment, Gross		23,803.6		23,743.5
Less: Accumulated Depreciation	Less: Accumulated Depreciation					Less: Accumulated Depreciation
	Electric and Natural Gas Utility		(5,575.8)		(5,387.0)	Electric and Natural Gas Utility		(5,842.6)		(5,777.8)
	Other		(207.7)		(196.2)	Other		(232.3)		(231.8)
Total Accumulated Depreciation	Total Accumulated Depreciation		(5,783.5)		(5,583.2)	Total Accumulated Depreciation		(6,074.9)		(6,009.6)
Property, Plant and Equipment, Net	Property, Plant and Equipment, Net		17,011.3		16,866.4	Property, Plant and Equipment, Net		17,728.7		17,733.9
Construction Work in Progress	Construction Work in Progress		967.4		709.8	Construction Work in Progress		1,082.0		913.1
Total Property, Plant and Equipment, Net	Total Property, Plant and Equipment, Net	$	17,978.7	$	17,576.2	Total Property, Plant and Equipment, Net	$	18,810.7	$	18,647.0

⁽¹⁾

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


	As of June 30, 2014								As of December 31, 2013								As of March 31, 2015								As of December 31, 2014
			NSTAR								NSTAR								NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric		PSNH		WMECO		CL&P		Electric		PSNH		WMECO		CL&P		Electric		PSNH		WMECO
Distribution	$	5,035.2	$	4,754.4	$	1,629.1	$	766.3	$	4,930.7	$	4,694.7	$	1,608.2	$	756.6	$	5,180.0	$	4,907.8	$	1,704.1	$	787.4	$	5,158.8	$	4,895.5	$	1,696.7	$	784.2
Transmission		3,108.1		1,798.9		713.5		841.1		3,071.9		1,772.3		695.7		826.4		3,274.7		1,950.6		794.6		891.9		3,274.0		1,928.5		789.7		891.0
Generation		-		-		1,134.0		33.9		-		-		1,131.2		21.1		-		-		1,137.8		34.4		-		-		1,136.5		34.4
Property, Plant and Equipment, Gross		8,143.3		6,553.3		3,476.6		1,641.3		8,002.6		6,467.0		3,435.1		1,604.1		8,454.7		6,858.4		3,636.5		1,713.7		8,432.8		6,824.0		3,622.9		1,709.6
Less: Accumulated Depreciation		(1,867.9)		(1,700.6)		(1,045.3)		(283.7)		(1,804.1)		(1,631.3)		(1,021.8)		(271.5)		(1,950.7)		(1,783.6)		(1,105.7)		(303.3)		(1,928.0)		(1,761.4)		(1,090.0)		(297.4)
Property, Plant and Equipment, Net		6,275.4		4,852.7		2,431.3		1,357.6		6,198.5		4,835.7		2,413.3		1,332.6		6,504.0		5,074.8		2,530.8		1,410.4		6,504.8		5,062.6		2,532.9		1,412.2
Construction Work in Progress		317.4		294.5		88.6		61.1		252.8		208.2		54.3		48.5		370.9		289.5		135.5		73.5		304.9		272.8		102.9		49.1
Total Property, Plant and Equipment, Net	$	6,592.8	$	5,147.2	$	2,519.9	$	1,418.7	$	6,451.3	$	5,043.9	$	2,467.6	$	1,381.1	$	6,874.9	$	5,364.3	$	2,666.3	$	1,483.9	$	6,809.7	$	5,335.4	$	2,635.8	$	1,461.3

As of March 31, 2015, PSNH had $1.1 billion in gross generation assets and Accumulated Depreciation of $497.1 million. These generation assets are the subject of a divestiture agreement in principle in a settlement Term Sheet entered into on March 11, 2015 between PSNH and key New Hampshire officials (Term Sheet) whereby, among other resolutions, PSNH has agreed to sell these assets. Upon completion of the sale, all remaining stranded costs will be recovered via bonds that will be secured by a non-bypassable charge to PSNH's customers. Consummation of the Term Sheet provisions is conditioned upon the enactment of New Hampshire legislation, completion of a final Settlement Agreement reflecting the provisions of the Term Sheet (Settlement Agreement), and NHPUC approval of the Settlement Agreement. See Note 8F, “Commitments and Contingencies – PSNH Generation Restructuring,” for further information.

DERIVATIVE INSTRUMENTS

The Regulated companies purchase and procure energy and energy-related products, ~~for their customers,~~ which are subject to price ~~volatility.~~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~~contract settlement amounts are recovered from, or refunded to, customers in their respective energy supply rates. ~~For NU's unregulated wholesale marketing contracts that expired on December 31, 2013, changes in fair values of derivatives were included in Net Income.~~

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

As of June 30, 2014

Commodity Supply and

Net Amount Recorded as
(Millions of Dollars)
Price Risk Management

Netting⁽¹⁾
Derivative Asset/(Liability)
Current Derivative Assets:

Level 2:

NU⁽¹⁾
$
0.4

$
(0.1)

$
0.3
Level 3:

NU, CL&P⁽¹⁾
16.4

(4.8)

11.6

Long-Term Derivative Assets:

Level 3:

NU, CL&P⁽¹⁾
$
111.7

$
(17.0)

$
94.7

Current Derivative Liabilities:

Level 2:

NU⁽¹⁾
$
(0.7)

$
0.2

$
(0.5)
Level 3:

NU

(87.8)

-

(87.8)

CL&P

(85.6)

-

(85.6)

NSTAR Electric

(2.2)

-

(2.2)

Long-Term Derivative Liabilities:

Level 3:

NU
$
(449.4)

$
-

$
(449.4)

CL&P

(445.3)

-

(445.3)

NSTAR Electric

(4.1)

-

(4.1)


									As of March 31, 2015						As of December 31, 2014
		As of December 31, 2013							Commodity Supply				Net Amount		Commodity Supply				Net Amount
		Commodity Supply and				Net Amount Recorded as			and Price Risk				Recorded as		and Price Risk					Recorded as
(Millions of Dollars)	(Millions of Dollars)	Price Risk Management		Netting⁽¹⁾		Derivative Asset/(Liability)		(Millions of Dollars)	Management		Netting⁽¹⁾		a Derivative		Management		Netting⁽¹⁾		a Derivative
Current Derivative Assets:	Current Derivative Assets:							Current Derivative Assets:
Level 3:								Level 3:
								ES	$	16.0	$	(6.6)	$	9.4	$	16.2	$	(6.6)	$	9.6
								CL&P		16.0		(6.6)		9.4		16.1		(6.6)		9.5
								NSTAR Electric		-		-		-		0.1		-		0.1

Long-Term Derivative Assets:								Long-Term Derivative Assets:
Level 3:								Level 3:
								ES, CL&P	$	88.3	$	(17.8)	$	70.5	$	93.5	$	(19.2)	$	74.3

Current Derivative Liabilities:								Current Derivative Liabilities:
Level 2:	Level 2:							Level 2:
	NU⁽¹⁾	$	1.9	$	(0.3)	$	1.6	ES	$	(3.2)	$	-	$	(3.2)	$	(9.8)	$	-	$	(9.8)
Level 3:	Level 3:							Level 3:
	NU⁽¹⁾		18.4		(9.8)		8.6	ES		(90.3)		-		(90.3)		(90.0)		-		(90.0)
	CL&P⁽¹⁾		17.1		(9.8)		7.3	CL&P		(88.2)		-		(88.2)		(88.5)		-		(88.5)
	NSTAR Electric		1.2		-		1.2	NSTAR Electric		(2.1)		-		(2.1)		(1.5)		-		(1.5)

Long-Term Derivative Assets:
Long-Term Derivative Liabilities:								Long-Term Derivative Liabilities:
Level 2:	Level 2:							Level 2:
	NU	$	0.2	$	-	$	0.2	ES	$	(0.2)	$	-	$	(0.2)	$	(0.3)	$	-	$	(0.3)
Level 3:	Level 3:							Level 3:
	NU⁽¹⁾		116.2		(42.2)		74.0	ES		(396.4)		-		(396.4)		(409.3)		-		(409.3)
	CL&P⁽¹⁾		113.6		(42.2)		71.4	CL&P		(395.0)		-		(395.0)		(406.2)		-		(406.2)
								NSTAR Electric		(1.4)		-		(1.4)		(3.1)		-		(3.1)
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 NUEversource elected to record net on the balance sheets. These amounts are subject to master netting agreements or similar agreements for which the right of offset exists.

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

~~Derivatives Not Designated as Hedges~~Derivative Contracts 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 ~~June 30, 2014~~March 31, 2015 and December 31, ~~2013, NU~~2014, Eversource had NYMEX ~~future~~financial contracts for natural gas futures in order to reduce variability associated with the purchase price of approximately ~~6.6~~5.3 million and ~~9.1~~8.8 million MMBtu of natural gas, respectively.

~~The following table presents~~For the three months ended March 31, 2015 and 2014, there were losses of $16.6 million and gains of $54.1 million, respectively, recorded as regulatory assets and liabilities, which reflect the current change in fair value ~~primarily recovered through rates from customers,~~ associated with ~~NU's~~Eversource's derivative ~~contracts not designated as hedges:~~contracts.

Amounts Recognized on Derivatives

For the Three Months Ended June 30,

For the Six Months Ended June 30,
(Millions of Dollars)

2014

2013

2014

2013
NU

Balance Sheets:

Regulatory Assets and Liabilities

$
111.6

$
22.2

$
166.0

$
50.1

Statements of Income:

Purchased Power, Fuel and Transmission

-

0.5

-

0.8

Credit Risk

Certain of ~~NU's~~Eversource's derivative contracts contain credit risk contingent ~~features.~~provisions. These ~~features~~provisions require NUEversource to maintain investment grade credit ratings from the major rating agencies and to post collateral for contracts in a net liability position over specified credit limits. As of ~~June 30, 2014, NSTAR Gas~~March 31, 2015, Eversource had approximately $3 million of derivative contracts in a net liability position that were subject to credit risk contingent ~~features. If NSTAR Gas' credit rating was downgraded below investment grade, NU~~provisions and would have been required to post additional collateral of approximately ~~$0.6~~$3 million ~~in collateral.~~if ES parent's unsecured debt credit ratings had been downgraded to below investment grade. As of December 31, ~~2013, there were no~~2014, Eversource had approximately $10 million of derivative contracts in a net liability position that were subject to credit risk contingent ~~features.~~provisions and would have been required to post additional collateral of approximately $10 million if ES parent's unsecured debt credit ratings had been downgraded to below investment grade.

~~Valuation~~Fair Value Measurements 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,~~Eversource's, including CL&P's and NSTAR Electric's, Level 3 derivative contracts and the range of the significant unobservable inputs utilized in the valuations over the duration of the contracts:


	As of June 30, 2014							As of December 31, 2013								As of March 31, 2015							As of December 31, 2014
		Range					Period Covered		Range					Period Covered			Range					Period Covered		Range					Period Covered
Energy Prices:															Energy Prices:
NU	$	63	-	66	per MWh		2018 - 2020	$	49	-	77	per MWh		2018 - 2029
CL&P	$	63	-	66	per MWh		2018 - 2020	$	56	-	58	per MWh		2018 - 2029
ES, CL&P															ES, CL&P	$	48			per MWh		2020	$	52			per MWh		2020

Capacity Prices:															Capacity Prices:
NU	$	3.13	-	13.00		per kW-Month	2016 - 2026	$	5.07	-	11.82		per kW-Month	2017 - 2029
ES															ES	$	8.80	-	12.98		per kW-Month	2016 – 2026	$	5.30	-	12.98		per kW-Month	2016 - 2026
CL&P	$	7.00	-	13.00		per kW-Month	2018 - 2026	$	5.07	-	10.42		per kW-Month	2017 - 2026	CL&P	$	11.13	-	12.98		per kW-Month	2019 – 2026	$	11.08	-	12.98		per kW-Month	2018 - 2026
NSTAR Electric	$	3.13	-	11.13		per kW-Month	2016 - 2019	$	5.07	-	7.38		per kW-Month	2017 - 2019	NSTAR Electric	$	8.80	-	11.13		per kW-Month	2016 – 2019	$	5.30	-	11.10		per kW-Month	2016 - 2019

Forward Reserve:															Forward Reserve:
NU, CL&P	$	3.30	-	9.50		per kW-Month	2014 - 2024	$	3.30	-	3.30		per kW-Month	2014 - 2024
ES, CL&P															ES, CL&P	$	5.80	-	9.50		per kW-Month	2015 – 2024	$	5.80	-	9.50		per kW-Month	2015 - 2024

REC Prices:															REC Prices:
NU	$	38	-	70	per REC		2014 - 2018	$	36	-	87	per REC		2014 - 2029
NSTAR Electric	$	38	-	70	per REC		2014 - 2018	$	36	-	70	per REC		2014 - 2018
ES, NSTAR Electric															ES, NSTAR Electric	$	45	-	50	per REC		2015 – 2018	$	38	-	56	per REC		2015 - 2018

Exit price premiums of 87 percent through 2524 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~~table presents changes in the Level 3 category of derivative assets and derivative liabilities measured at fair value on a recurring basis. The derivative assets and liabilities are presented on a net basis.

For the Three Months Ended June 30,

For the Six Months Ended June 30,

2014

2013

2014

2013
(Millions of Dollars)
NU

NU

NU

NU
Derivatives, Net:

Fair Value as of Beginning of Period
$
(564.3)

$
(833.1)

$
(635.2)

$
(878.6)
Net Realized/Unrealized Gains Included in:

Net Income

-

1.3

-

7.1

Regulatory Assets and Liabilities

111.8

22.7

161.3

48.9
Settlements

21.6

21.0

43.0

34.5
Fair Value as of End of Period
$
(430.9)

$
(788.1)

$
(430.9)

$
(788.1)

For the Three Months Ended June 30,

2014

2013
(Millions of Dollars)
CL&P

NSTAR Electric

CL&P

NSTAR Electric
Derivatives, Net:

Fair Value as of Beginning of Period
$
(557.0)

$
(7.3)

$
(819.6)

$
(13.6)
Net Realized/Unrealized Gains/(Losses)
Included in Regulatory Assets and Liabilities

112.2

(0.4)

21.9

(0.5)
Settlements

20.2

1.4

21.9

1.0
Fair Value as of End of Period
$
(424.6)

$
(6.3)

$
(775.8)

$
(13.1)


											For the Three Months Ended March 31,
		For the Six Months Ended June 30,									2015						2014
		2014				2013									NSTAR						NSTAR
(Millions of Dollars)	(Millions of Dollars)	CL&P		NSTAR Electric		CL&P		NSTAR Electric		(Millions of Dollars)	ES		CL&P		Electric		ES		CL&P		Electric
Derivatives, Net:	Derivatives, Net:									Derivatives, Net:
Fair Value as of Beginning of Period	Fair Value as of Beginning of Period	$	(630.6)	$	(7.3)	$	(866.2)	$	(14.9)	Fair Value as of Beginning of Period	$	(415.4)	$	(410.9)	$	(4.5)	$	(635.2)	$	(630.6)	$	(7.3)
Net Realized/Unrealized Gains/(Losses) Included in Regulatory Assets and Liabilities	Net Realized/Unrealized Gains/(Losses) Included in Regulatory Assets and Liabilities		164.5		(0.5)		46.3		0.2	Net Realized/Unrealized Gains/(Losses) Included in Regulatory Assets and Liabilities		(12.1)		(12.1)		-		49.2		52.0		(0.1)
Settlements	Settlements		41.5		1.5		44.1		1.6	Settlements		20.7		19.7		1.0		21.7		21.6		0.1
Fair Value as of End of Period	Fair Value as of End of Period	$	(424.6)	$	(6.3)	$	(775.8)	$	(13.1)	Fair Value as of End of Period	$	(406.8)	$	(403.3)	$	(3.5)	$	(564.3)	$	(557.0)	$	(7.3)

MARKETABLE SECURITIES

NUEversource 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~~The Company elected to record mutual funds ~~designated as available-for-sale~~ at fair value and certain other equity investments as trading securities, with the changes in fair values recorded in Other Income, Net on the statements of income. As of ~~June 30,~~March 31, 2015 and December 31, 2014, the mutual funds and equity investments were classified as Level 1 in the fair value hierarchy and totaled ~~$59.6~~$86.7 million and ~~$24.9~~$85.1 million, respectively. ~~As of December 31, 2013, the mutual funds were classified as Level 1, and totaled $57.2 million. Net gains on the mutual funds were $2.2 million and $0.1 million for~~For the three months ended ~~June 30,~~March 31, 2015 and 2014, ~~and 2013, respectively, and $2.4~~net gains on these securities of $1.6 million and ~~$4.3~~$0.7 million, ~~for the six months ended June 30, 2014 and 2013, respectively. Net gains on the equity investments~~respectively, were ~~$0.9 million and $1.4 million for the three and six months ended June 30, 2014, respectively. Dividend income is~~ recorded in Other Income, Net on the statements of income. Dividend income is recorded in Other Income, Net 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~~Eversource's and WMECO's available-for-sale securities. These securities are recorded at fair value and are included in current and long-term Marketable Securities on the balance sheets.

As of June 30, 2014

Pre-Tax

Pre-Tax

Amortized

Unrealized

Unrealized

(Millions of Dollars)
Cost

Gains

Losses

Fair Value
NU

Debt Securities⁽¹⁾
$
308.3

$
7.3

$
(0.3)

$
315.3

Equity Securities⁽¹⁾
163.5

66.7

-

230.2

WMECO

Debt Securities⁽²⁾
58.0

-

-

58.0


		As of December 31, 2013									As of March 31, 2015								As of December 31, 2014
				Pre-Tax		Pre-Tax							Pre-Tax		Pre-Tax						Pre-Tax		Pre-Tax
		Amortized		Unrealized		Unrealized					Amortized		Unrealized		Unrealized				Amortized		Unrealized		Unrealized
(Millions of Dollars)	(Millions of Dollars)	Cost		Gains		Losses		Fair Value		(Millions of Dollars)	Cost		Gains		Losses		Fair Value		Cost		Gains		Losses		Fair Value
NU
	Debt Securities⁽¹⁾	$	299.2	$	2.5	$	(2.1)	$	299.6
ES										ES
	Equity Securities⁽¹⁾		163.6		60.5		-		224.1	Debt Securities⁽¹⁾	$	318.2	$	8.2	$	(0.1)	$	326.3	$	313.0	$	7.5	$	(0.3)	$	320.2
										Equity Securities⁽¹⁾		159.5		77.0		-		236.5		160.6		73.3		-		233.9
WMECO	WMECO									WMECO
	Debt Securities⁽²⁾		57.9		-		-		57.9	Debt Securities⁽²⁾		58.2		-		-		58.2		58.2		-		(0.1)		58.1

⁽¹⁾

~~NU's~~Eversource's amounts include CYAPC's and YAEC's marketable securities held in nuclear decommissioning trusts of ~~$444.3~~$458.3 million and ~~$424~~$450.8 million as of ~~June 30, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, 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 recorded in Marketable Securities with the corresponding offset into 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 Marketable Securities with the corresponding offset to 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 NUEversource 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~~Eversource's benefit trust, Other Long-Term Assets for WMECO, and are offset in Other Long-Term Liabilities for CYAPC and YAEC. NUEversource utilizes the specific identification basis method for the NUEversource benefit trust, and the average cost basis method for the WMECO trust and the CYAPC and YAEC nuclear decommissioning trusts to compute the realized gains and losses on the sale of available-for-sale securities.

Contractual Maturities: As of ~~June 30, 2014,~~March 31, 2015, the contractual maturities of available-for-sale debt securities ~~are~~were as follows:


		NU				WMECO					ES				WMECO
		Amortized				Amortized					Amortized				Amortized
(Millions of Dollars)	(Millions of Dollars)	Cost		Fair Value		Cost		Fair Value		(Millions of Dollars)	Cost		Fair Value		Cost		Fair Value
Less than one year⁽¹⁾	Less than one year⁽¹⁾	$	75.9	$	75.8	$	19.2	$	19.2	Less than one year⁽¹⁾	$	59.9	$	59.9	$	33.2	$	33.2
One to five years	One to five years		73.9		74.6		31.9		32.0	One to five years		83.3		83.8		21.3		21.3
Six to ten years	Six to ten years		56.1		57.7		2.7		2.7	Six to ten years		61.6		63.5		0.6		0.6
Greater than ten years	Greater than ten years		102.4		107.2		4.2		4.1	Greater than ten years		113.4		119.1		3.1		3.1
Total Debt Securities	Total Debt Securities	$	308.3	$	315.3	$	58.0	$	58.0	Total Debt Securities	$	318.2	$	326.3	$	58.2	$	58.2

⁽¹⁾

Amounts in the Less than one year NUEversource 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					ES				WMECO
(Millions of Dollars)	(Millions of Dollars)	June 30, 2014		December 31, 2013		June 30, 2014		December 31, 2013		(Millions of Dollars)	As of March 31, 2015		As of December 31, 2014		As of March 31, 2015		As of December 31, 2014
Level 1:	Level 1:									Level 1:
	Mutual Funds and Equities	$	314.7	$	281.3	$	-	$	-	Mutual Funds and Equities	$	323.2	$	319.0	$	-	$	-
	Money Market Funds		42.3		32.9		2.0		10.9	Money Market Funds		32.9		24.9		10.5		4.3
Total Level 1	Total Level 1	$	357.0	$	314.2	$	2.0	$	10.9	Total Level 1	$	356.1	$	343.9	$	10.5	$	4.3
Level 2:	Level 2:									Level 2:
	U.S. Government Issued Debt Securities (Agency and Treasury)	$	40.6	$	61.4	$	-	$	6.8	U.S. Government Issued Debt Securities (Agency and Treasury)	$	46.0	$	51.3	$	-	$	-
	Corporate Debt Securities		61.8		53.6		15.8		15.1	Corporate Debt Securities		157.3		49.1		14.4		14.7
	Asset-Backed Debt Securities		36.5		30.4		15.2		9.0	Asset-Backed Debt Securities		36.5		54.1		12.1		14.5
	Municipal Bonds		109.5		105.5		11.7		11.2	Municipal Bonds		31.9		116.3		12.9		13.0
	Other Fixed Income Securities		24.6		15.8		13.3		4.9	Other Fixed Income Securities		21.7		24.5		8.3		11.6
Total Level 2	Total Level 2	$	273.0	$	266.7	$	56.0	$	47.0	Total Level 2	$	293.4	$	295.3	$	47.7	$	53.8
Total Marketable Securities	Total Marketable Securities	$	630.0	$	580.9	$	58.0	$	57.9	Total Marketable Securities	$	649.5	$	639.2	$	58.2	$	58.1

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.

6.
SHORT-TERM AND LONG-TERM DEBT

Credit Agreements and Commercial Paper Programs: ~~Effective July 23, 2014, NU~~ES parent, CL&P, PSNH, WMECO, NSTAR Gas and Yankee Gas ~~amended their joint~~are parties to a five-year $1.45 billion revolving credit facility ~~to extend the expiration date an additional year to~~that expires September 6, 2019. The revolving credit facility is ~~to be~~ used primarily to backstop NUES parent's $1.45 billion commercial paper program. The commercial paper program allows NUES parent to issue commercial paper as a form of short-term debt. As of ~~June 30, 2014~~March 31, 2015 and December 31, ~~2013, NU~~2014, ES parent had ~~$710.5~~$788 million and ~~$1.01~~approximately $1.1 billion, respectively, in short-term borrowings outstanding under the NUES parent commercial paper program, leaving ~~$739.5~~$662 million and ~~$435.5~~$348.9 million of available borrowing capacity as of ~~June 30, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, respectively. The weighted-average interest rate on these borrowings as of ~~June 30, 2014~~March 31, 2015 and December 31, ~~2013~~2014 was ~~0.25~~0.53 percent and ~~0.24~~0.43 percent, respectively, which is generally based on A2/P2 rated commercial paper. As of ~~June 30, 2014,~~March 31, 2015, there were intercompany loans from NUES parent of ~~$6.4~~$190.1 million to CL&P, ~~$95~~$82 million to PSNH and ~~$15.9~~$70.5 million to WMECO. As of December 31, ~~2013,~~2014, there were intercompany loans from NUES parent of ~~$287.3~~$133.4 million to CL&P, ~~and $86.5~~$90.5 million to ~~PSNH.~~ PSNH and $21.4 million to WMECO.

~~Effective July 23, 2014,~~ NSTAR Electric ~~amended its~~has a five-year $450 million revolving credit facility ~~to extend the expiration date an additional year to~~that expires September 6, 2019. This facility serves to backstop NSTAR Electric's existing $450 million commercial paper program. As of ~~June 30, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, NSTAR Electric had ~~$194.5~~$215.5 million and ~~$103.5~~$302 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving ~~$255.5~~$234.5 million and ~~$346.5~~$148 million of available borrowing capacity as of ~~June 30, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, respectively. The weighted-average interest rate on these borrowings as of ~~June 30, 2014~~March 31, 2015 and December 31, ~~2013~~2014 was ~~0.16~~0.35 percent and ~~0.13~~0.27 percent, respectively, which is generally based on A2/P1 rated commercial paper.

~~Amounts~~Except as described below, amounts outstanding under the commercial paper programs are ~~generally~~ included in Notes Payable for NUEversource 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 NUES parent to CL&P, PSNH and WMECO are included in Notes Payable to NUES Parent and classified in current liabilities on the balance sheets. ~~See the~~~~Long-Term Debt~~~~portion of this Note immediately below for further information on the Yankee Gas $100 million bond issuance~~Intercompany loans from ES parent to CL&P, PSNH and ~~its impact on the NU~~WMECO are eliminated in consolidation in Eversource's balance ~~sheet as of December 31, 2013.~~

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

Long-Term Debt: On January ~~2, 2014, Yankee Gas~~15, 2015, ES parent issued ~~$100~~$150 million of ~~4.82~~1.60 percent Series ~~L First Mortgage Bonds,~~G Senior Notes, 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~~2018 and ~~to pay $25 million in short-term borrowings. In accordance with applicable accounting guidance, these amounts were classified as Long-Term Debt on NU's balance sheet as of December 31, 2013.~~

~~On March 7, 2014, NSTAR Electric issued~~ $300 million of ~~4.40~~3.15 percent ~~debentures,~~Series H Senior Notes, due to mature in ~~2044. The proceeds, net of issuance costs, were used to repay the $300 million of 4.875 percent debentures that matured on April 15, 2014.~~

~~On April 24, 2014, CL&P issued $250 million of 4.30 percent 2014 Series A First Mortgage Bonds, due to mature in April 2044.~~2025. The proceeds, net of issuance costs, were used to repay short-term ~~borrowings.~~borrowings outstanding under the ES parent commercial paper program. As the debt issuances refinanced short-term debt, the short-term debt was classified as Long-Term Debt as of December 31, 2014.

On ~~July 15, 2014, PSNH~~April 1, 2015, CL&P repaid at maturity the ~~$50~~$100 million ~~of 5.25~~5.00 percent 2005 Series LA First and Refunding Mortgage Bonds using short-term ~~debt.~~
~~Working Capital:~~ ~~Each of NU,~~borrowings. On April 1, 2015, CL&P ~~NSTAR Electric, PSNH and WMECO use its available capital resources~~also redeemed the $62 million 1996A Series 1.55 percent PCRBs that were subject to fund its respective construction expenditures, meet debt requirements, pay operating costs, including storm-related costs, pay dividends and fund other corporate obligations, such as pension contributions. The current growth in NU's transmission construction expenditures utilizes a significant amount of cash for projects that have a long-term return on investment and recovery period. In addition, NU's Regulated companies recover their electric and natural gas distribution construction expenditures as the related project costs are depreciated over the life of the assets. This impacts the timing of the revenue stream designed to fully recover the total investment plus a return on the equity portion of the cost and related financing costs. These factors have resulted in current liabilities exceeding current assets by approximately $730 million, $220 million and $200 million at NU, CL&P and NSTAR Electric, respectively, as of June 30, 2014.mandatory tender, using short term borrowings.

~~As of June 30, 2014, $366.7~~Long-Term Debt Issuance Authorization: On April 3, 2015, the DPU authorized NSTAR Gas to issue up to $100 million ~~of NU's obligations classified as current liabilities relates to~~in long-term debt ~~that will be paid in~~for the next 12 months, consisting of $312 million for CL&P, $4.7 million at NSTAR Electric and $50 million for PSNH. In addition, $28.9 million relates to the amortization of the purchase accounting fair value adjustment that will be amortized in the next twelve months. NU, with its strong credit ratings, has several options available in the financial markets to repay or refinance these maturities with the issuance of new long-term debt. NU, CL&P, NSTAR Electric, PSNH and WMECO will reduce their short-term borrowings with cash received from operating cash flows or with the issuance of new long-term debt, determined considering capital requirements and maintenance of NU's credit rating and profile. Management expects the future operating cash flows of NU, CL&P, NSTAR Electric, PSNH and WMECO, along with the access to financial markets, will be sufficient to meet any future operating requirements and capital investment forecasted opportunities.period through December 31, 2015.

3023

7.
PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

As of December 31, 2014, Eversource Service sponsored two defined benefit retirement plans that covered eligible employees, including employees of CL&P, NSTAR Electric, PSNH and WMECO. Effective January 1, 2015, the two pension plans were merged into one plan, sponsored by Eversource Service. As of December 31, 2014, Eversource Service also sponsored defined benefit postretirement plans that provide certain retiree benefits, primarily medical, dental and life insurance, to retiring employees that meet certain age and service eligibility requirements, including employees of CL&P, NSTAR Electric, PSNH and WMECO. Effective January 1, 2015, the postretirement plans were merged into one plan, sponsored by Eversource Service.

The components of net periodic benefit expense for the Pension, SERP and PBOP Plans are ~~detailed~~shown below. The net periodic benefit expense and the intercompany allocations less the capitalized portion of pension, SERP 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, SERP and PBOP expense reflected in the statements of cash flows for CL&P, NSTAR Electric, PSNH and WMECO does not include the intercompany allocations and the corresponding capitalized portion, as these amounts are cash settled on a short-term basis.

Pension and SERP

Pension and SERP

Pension and SERP

For the Three Months Ended

For the Six Months Ended

For the Three Months Ended

June 30, 2014

June 30, 2013

June 30, 2014

June 30, 2013

March 31, 2015

March 31, 2014
(Millions of Dollars)
(Millions of Dollars)
NU

NU

NU

NU
(Millions of Dollars)
ES⁽¹⁾

ES
Service Cost
Service Cost
$
19.1

$
24.6

$
41.5

$
51.1
Service Cost
$
23.2

$
22.3
Interest Cost
Interest Cost

56.3

51.9

113.0

103.5
Interest Cost

56.6

56.6
Expected Return on Plan Assets
Expected Return on Plan Assets

(77.7)

(68.6)

(155.4)

(139.0)
Expected Return on Plan Assets

(84.3)

(77.7)
Actuarial Loss
Actuarial Loss

31.7

52.6

64.7

105.5
Actuarial Loss

38.9

33.0
Prior Service Cost
Prior Service Cost

1.1

1.0

2.1

2.1
Prior Service Cost

0.9

1.1
Total Net Periodic Benefit Expense
Total Net Periodic Benefit Expense
$
30.5

$
61.5

$
65.9

$
123.2
Total Net Periodic Benefit Expense
$
35.3

$
35.3
Capitalized Pension Expense
Capitalized Pension Expense
$
8.7

$
19.9

$
18.4

$
36.6
Capitalized Pension Expense
$
9.6

$
9.7

PBOP

PBOP

PBOP

For the Three Months Ended

For the Six Months Ended

For the Three Months Ended

June 30, 2014

June 30, 2013

June 30, 2014

June 30, 2013

March 31, 2015

March 31, 2014
(Millions of Dollars)
(Millions of Dollars)
NU

NU

NU

NU
(Millions of Dollars)
ES⁽¹⁾

ES
Service Cost
Service Cost
$
3.2

$
3.7

$
6.3

$
8.5
Service Cost
$
4.2

$
3.0
Interest Cost
Interest Cost

12.1

10.9

24.7

23.6
Interest Cost

11.9

12.6
Expected Return on Plan Assets
Expected Return on Plan Assets

(15.8)

(13.9)

(31.6)

(27.7)
Expected Return on Plan Assets

(16.8)

(15.7)
Actuarial Loss
Actuarial Loss

3.0

4.7

6.0

13.0
Actuarial Loss

1.8

3.0
Prior Service Credit
Prior Service Credit

(0.7)

(0.5)

(1.4)

(1.1)
Prior Service Credit

(0.1)

(0.6)
Total Net Periodic Benefit Expense
Total Net Periodic Benefit Expense
$
1.8

$
4.9

$
4.0

$
16.3
Total Net Periodic Benefit Expense
$
1.0

$
2.3
Capitalized PBOP Expense
Capitalized PBOP Expense
$
0.4

$
1.5

$
0.8

$
5.0
Capitalized PBOP Expense
$
0.2

$
0.4

Pension and SERP

Pension and SERP

For the Three Months Ended June 30, 2014

For the Three Months Ended June 30, 2013

For the Three Months Ended March 31, 2015

For the Three Months Ended March 31, 2014

NSTAR

NSTAR

NSTAR

NSTAR

(Millions of Dollars)
(Millions of Dollars)
CL&P

Electric

PSNH

WMECO

CL&P

Electric⁽¹⁾
PSNH

WMECO
(Millions of Dollars)
CL&P

Electric

PSNH⁽¹⁾
WMECO

CL&P

Electric

PSNH

WMECO
Service Cost
Service Cost
$
5.0

$
3.0

$
2.3

$
0.8

$
6.3

$
7.3

$
3.2

$
1.2
Service Cost
$
6.0

$
3.8

$
2.9

$
1.1

$
5.2

$
4.6

$
2.8

$
1.0
Interest Cost
Interest Cost

12.4

10.3

5.8

2.5

12.1

14.7

5.9

2.5
Interest Cost

12.7

10.2

5.9

2.5

13.3

10.2

6.5

2.7
Expected Return on Plan Assets
Expected Return on Plan Assets

(18.7)

(15.7)

(9.3)

(4.4)

(18.4)

(20.2)

(9.2)

(4.4)
Expected Return on Plan Assets

(19.7)

(17.6)

(10.0)

(4.7)

(19.4)

(15.8)

(10.2)

(4.6)
Actuarial Loss
Actuarial Loss

8.2

5.9

2.8

1.7

13.9

14.6

5.4

2.9
Actuarial Loss

8.2

9.6

3.0

1.6

9.1

5.8

3.3

1.9
Prior Service Cost/(Credit)

0.5

-

0.1

0.1

0.5

(0.1)

0.1

0.1
Prior Service Cost
Prior Service Cost

0.4

-

0.1

0.1

0.5

-

0.2

0.1
Total Net Periodic Benefit Expense
Total Net Periodic Benefit Expense
$
7.4

$
3.5

$
1.7

$
0.7

$
14.4

$
16.3

$
5.4

$
2.3
Total Net Periodic Benefit Expense
$
7.6

$
6.0

$
1.9

$
0.6

$
8.7

$
4.8

$
2.6

$
1.1
Intercompany Allocations
Intercompany Allocations
$
7.5

$
1.4

$
2.1

$
1.4

$
11.3

$
(2.2)

$
2.6

$
2.0
Intercompany Allocations
$
6.4

$
3.6

$
1.7

$
1.2

$
6.8

$
2.4

$
1.9

$
1.3
Capitalized Pension Expense
Capitalized Pension Expense
$
4.4

$
1.0

$
0.8

$
0.6

$
7.0

$
6.5

$
1.7

$
1.3
Capitalized Pension Expense
$
4.3

$
2.8

$
0.8

$
0.5

$
4.9

$
1.9

$
0.9

$
0.8

Pension and SERP

For the Six Months Ended June 30, 2014

For the Six Months Ended June 30, 2013

NSTAR

NSTAR

(Millions of Dollars)
CL&P

Electric

PSNH

WMECO

CL&P

Electric⁽¹⁾
PSNH

WMECO
Service Cost
$
10.2

$
7.6

$
5.1

$
1.9

$
12.4

$
16.5

$
6.5

$
2.4
Interest Cost

25.7

20.6

12.3

5.2

24.2

29.0

11.9

5.0
Expected Return on Plan Assets

(38.0)

(31.5)

(19.5)

(9.0)

(36.9)

(42.2)

(16.8)

(8.7)
Actuarial Loss

17.3

11.7

6.0

3.5

28.0

29.1

10.8

5.9
Prior Service Cost/(Credit)

0.9

-

0.3

0.2

0.9

(0.1)

0.3

0.2
Total Net Periodic Benefit Expense
$
16.1

$
8.4

$
4.2

$
1.8

$
28.6

$
32.3

$
12.7

$
4.8
Intercompany Allocations
$
14.3

$
3.8

$
4.2

$
2.7

$
22.1

$
(4.1)

$
5.2

$
4.0
Capitalized Pension Expense
$
9.3

$
2.9

$
1.7

$
1.4

$
14.0

$
11.8

$
3.9

$
2.6

PBOP

For the Three Months Ended March 31, 2015

For the Three Months Ended March 31, 2014

NSTAR

NSTAR

(Millions of Dollars)
CL&P

Electric

PSNH⁽¹⁾
WMECO

CL&P

Electric

PSNH

WMECO
Service Cost
$
0.6

$
1.3

$
0.4

$
0.1

$
0.6

$
0.7

$
0.4

$
0.1
Interest Cost

1.8

4.8

1.0

0.4

2.1

4.9

1.1

0.5
Expected Return on Plan Assets

(2.8)

(6.8)

(1.5)

(0.6)

(2.7)

(6.4)

(1.4)

(0.6)
Actuarial Loss/(Gain)

0.2

0.8

0.1

-

1.1

(0.1)

0.5

0.1
Prior Service Credit

-

(0.1)

-

-

-

(0.5)

-

-
Total Net Periodic Benefit
  Expense/(Income)
$
(0.2)

$
-

$
-

$
(0.1)

$
1.1

$
(1.4)

$
0.6

$
0.1
Intercompany Allocations
$
0.5

$
0.3

$
0.1

$
0.1

$
1.1

$
0.1

$
0.3

$
0.2
Capitalized PBOP Expense/(Income)
$
-

$
0.1

$
-

$
-

$
0.5

$
(0.5)

$
0.2

$
0.1

⁽¹⁾
Amounts exclude approximately $1 million that represented deferred regulatory assets.

3124

PBOP

For the Three Months Ended June 30, 2014

For the Three Months Ended June 30, 2013
(Millions of Dollars)
CL&P

NSTAR Electric

PSNH

WMECO

CL&P

PSNH

WMECO
Service Cost
$
0.5

$
0.8

$
0.3

$
0.1

$
0.9

$
0.6

$
0.2
Interest Cost

1.9

4.8

1.0

0.4

2.0

1.0

0.4
Expected Return on Plan Assets

(2.5)

(6.5)

(1.3)

(0.6)

(2.5)

(1.3)

(0.6)
Actuarial Loss/(Gain)

1.0

(0.2)

0.6

0.1

1.9

0.9

0.3
Prior Service Credit

-

(0.5)

-

-

-

-

-
Total Net Periodic Benefit Expense/(Income)
$
0.9

$
(1.6)

$
0.6

$
0.0

$
2.3

$
1.2

$
0.3
Intercompany Allocations
$
1.1

$
-

$
0.3

$
0.2

$
1.9

$
0.4

$
0.3
Capitalized PBOP Expense/(Income)
$
0.5

$
(0.5)

$
0.2

$
-

$
1.2

$
0.4

$
0.2

PBOP

For the Six Months Ended June 30, 2014

For the Six Months Ended June 30, 2013
(Millions of Dollars)
CL&P

NSTAR Electric

PSNH

WMECO

CL&P

PSNH

WMECO
Service Cost
$
1.1

$
1.6

$
0.7

$
0.2

$
1.7

$
1.1

$
0.4
Interest Cost

4.0

9.7

2.1

0.8

3.9

2.0

0.8
Expected Return on Plan Assets

(5.2)

(13.0)

(2.7)

(1.1)

(5.0)

(2.6)

(1.2)
Actuarial Loss/(Gain)

2.1

(0.3)

1.1

0.2

3.7

1.8

0.6
Prior Service Credit

-

(0.9)

-

-

-

-

-
Total Net Periodic Benefit Expense/(Income)
$
2.0

$
(2.9)

$
1.2

$
0.1

$
4.3

$
2.3

$
0.6
Intercompany Allocations
$
2.2

$
0.1

$
0.6

$
0.4

$
3.6

$
0.8

$
0.6
Capitalized PBOP Expense/(Income)
$
1.0

$
(1.0)

$
0.4

$
0.1

$
2.4

$
0.7

$
0.4

⁽¹⁾
~~NSTAR Electric's pension amounts for the three and six months ended June 30, 2013 do not include SERP expense.~~

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

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

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

8.
COMMITMENTS AND CONTINGENCIES

A.
Environmental Matters
General: ~~NU,~~Eversource, 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,~~Eversource, CL&P, NSTAR Electric, PSNH and WMECO have an active environmental auditing and training program and believe that they are substantially in compliance with all enacted laws and regulations.

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

As of June 30, 2014

As of December 31, 2013
As of March 31, 2015

As of December 31, 2014

Reserve

Reserve

Reserve

Reserve

Number of Sites

(in millions)

Number of Sites

(in millions)
Number of Sites

(in millions)

Number of Sites

(in millions)
NU

66

$
34.5

68

$
35.4
ES

65

$
43.6

65

$
43.3
CL&P

17

4.2

18

3.4

16

5.0

16

3.8
NSTAR Electric

14

1.2

12

1.2

14

1.7

13

1.1
PSNH

13

5.3

15

5.4

12

3.4

13

5.2
WMECO

5

0.6

5

0.4

4

0.6

4

0.5

Included in the NUEversource 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~~$35.4 million and ~~$31.4~~$38.8 million as of ~~June 30, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, respectively, and relates primarily to the natural gas business segment.

32

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

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

July - December

(Millions of Dollars)
2014

2015

2016

2017

2018

Thereafter

Total
Renewable Energy

NSTAR Electric
$
43.6

$
86.3

$
93.7

$
89.8

$
53.3

$
302.8

$
669.5
WMECO

-

-

2.4

2.4

2.4

28.9

36.1

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

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

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

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

D.
Guarantees and Indemnifications
NUES 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.

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

ES parent has also guaranteed certain indemnification and other obligations as a result of the sales of former unregulated subsidiaries and the termination of an unregulated business, with maximum exposures either not specified or not material.

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~~ES parent's guarantees of its subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, as of ~~June 30, 2014:~~March 31, 2015:

Maximum Exposure

~~Subsidiary~~Company

Description

(in millions)

Expiration Dates
Various

Surety Bonds
$
~~67.0~~
~~2014 - 2016~~⁽¹⁾
$
~~Various~~54.6

~~New England Hydro Companies~~' ~~Long-Term Debt~~
$
~~2.5~~
~~Unspecified~~2015 - 2016

~~NUSCO~~Eversource Service and ~~RRR~~Rocky River Realty Company

Lease Payments for Vehicles and Real Estate

$
~~16.0~~
13.8

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 NUES parent to post collateral in the event that the unsecured debt credit ratings of NUEversource are downgraded.

E.C.
FERC ~~Base~~ ROE Complaints
~~On September 30,~~Beginning in 2011, ~~a complaint was~~three separate complaints were filed ~~jointly~~ at FERC ~~under Sections 206 and 306~~by combinations of ~~the Federal Power Act by several~~ New England state attorneys general, state regulatory commissions, consumer advocates, consumer groups, municipal parties and other parties (the "Complainants"). ~~The~~In the first complaint, filed in 2011, the Complainants alleged that the NETOs' base ROE of 11.14 percent that ~~has been~~was 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~~markets, and sought an order to reduce it prospectively from the ~~base ROE, effective~~date of the final FERC order and for the 15-month period beginning October 1, 2011 to December 31, 2012 (the "first complaint refund period"). In the second and ~~to require refunds. The FERC set~~third complaints, filed in 2012 and 2014, the ~~case~~Complainants challenged the NETOs' base ROE and sought refunds for ~~trial before a FERC ALJ after settlement negotiations were unsuccessful in August 2012.~~

33the 15-month periods beginning December 27, 2012 and July 31, 2014.

~~On August 6, 2013,~~In 2014, the FERC ~~ALJ issued an initial decision finding~~determined that the base ROE in effect from October 1, 2011 through December 31, 2012 (refund period) was not reasonable, and recommended separate base ROEs for the refund period of 10.6 percent and for the period beginning when FERC issues its final decision (prospective period) of 9.7 percent, leaving policy considerations and additional adjustments to the FERC. In the third quarter of 2013, the Company recorded a series of reservesshould be set at its electric subsidiaries to recognize the potential financial impact from the FERC ALJ's initial decision for the refund period. The aggregate after-tax charge to third quarter 2013 earnings totaled $14.3 million at NU, which represented reserves of $7.7 million at CL&P, $3.4 million at NSTAR Electric, $1.4 million at PSNH and $1.8 million at WMECO.

~~On June 19, 2014, FERC issued an order partially affirming and partially reversing the ALJ's initial decision. FERC set a single tentative base ROE of~~ 10.57 percent for the 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 at the 75^th ~~percentile of this new zone. FERC also stated~~ 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, ~~produced~~which was set at 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 of 10.57 percent prospectively from October 16, 2014. The NETOs and the Complainants sought rehearing from FERC. In late 2014, the NETOs made a compliance filing, which was challenged by ~~this methodology.~~the Complainants, and the Company began refunding amounts from the first complaint period.

On March 3, 2015, FERC ~~instituted a paper hearing~~issued an order denying all issues raised on ~~the long-term growth rate portion of the methodology, before it issues a final determination on the base ROE. On July 21, 2014,~~rehearing by the NETOs and Complainants ~~filed rehearing requests~~ in ~~this proceeding.~~ the first base ROE complaint. The FERC order upheld the base ROE of 10.57 percent for the first complaint refund period and prospectively from October 16, 2014, and upheld that the utility's total ROE (the base ROEplus anyincentive adders) for the transmission assets to which the adder applies is capped at the top of the zone of reasonableness, which is currently set at 11.74 percent. As a result ofclarifying information related to how the ROE cap is applied, which is

25

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

~~Though NU cannot predict the ultimate outcome of this proceeding,~~contained in the ~~second~~order, Eversource adjusted its reservein the first quarter of ~~2014, the Company recorded~~2015 and recognized a ~~series of reserves at its electric subsidiaries to recognize the potential financial impact from the FERC’s two orders issued on June 19, 2014 for the two refund periods. The aggregate after-tax~~pre-tax charge to ~~second quarter 2014~~ earnings ~~totaled $32.1~~(excluding interest) of $20 million, ~~at NU,~~of which ~~represented reserves of $18.5~~$12.5 million was recorded at CL&P, ~~$6.1~~$2.4 million at NSTAR Electric, $2$1 million at PSNH, and ~~$5.5 million at WMECO.~~

As of June 30, 2014, the cumulative pre-tax reserves totaled $79.3 million at NU, $44.7 million at CL&P, $16.2 million at NSTAR Electric, $6.2 million at PSNH and $12.2 million at WMECO. As of December 31, 2013, the pre-tax reserves totaled $24.6 million at NU, $13.3 million at CL&P, $5.9 million at NSTAR Electric, $2.4 million at PSNH and $3$4.1 million at WMECO.   The ~~reserves were~~pre-tax charge was recorded ~~in each electric subsidiary's respective transmission~~as a regulatory ~~tracker mechanism~~liability and as a reduction of ~~operating revenues. See Note 2, “Regulatory Accounting,” for further information.~~Operating Revenues.

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

F.D.
~~CPSL~~2014 Comprehensive Settlement Agreement
~~Since 2006,~~On March 2, 2015, the DPU approved the comprehensive settlement agreement between NSTAR Electric, ~~has been recovering incremental costs related to~~NSTAR Gas and the ~~DPU-approved Safety and Reliability Programs. From~~Massachusetts Attorney General (the "Settlement") as filed with the DPU on December 31, 2014. The Settlement resolved the outstanding NSTAR Electric CPSL program filings for 2006 through 2011, ~~cumulative costs associated with~~ the ~~CPSL program resulted~~NSTAR Electric and NSTAR Gas PAM and energy efficiency-related customer billing adjustments reported in ~~an incremental revenue requirement to customers of approximately $83 million. These amounts included incremental operations and maintenance costs~~2012, and the recovery of LBR related ~~revenue requirement~~to NSTAR Electric's energy efficiency programs for ~~specific capital investments relative~~2008 through 2011 (11 dockets in total). As a result, NSTAR Electric and NSTAR Gas will refund $42.5 million and $2.2 million, respectively, to customers. The refund was recorded as a regulatory liability as of March 31, 2015 and NSTAR Electric recognized a $21.7 million pre-tax benefit in the ~~CPSL programs.~~first quarter of 2015.

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. E.

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.

G.
Basic Service Bad Debt Adder
In accordance with a generic 2005 DPU order, electric utilities in Massachusetts recover the energy-related portion of bad debt costs in their Basic Service rates. In February 2007, NSTAR Electric filed its 2005 through 2006 Basic Service reconciliation with the DPU proposing an adjustment related to the increase of its Basic Service bad debt charge-offs. ~~The~~In June 2007, the DPU ~~issued an order approving~~approved NSTAR Electric's proposed adjustment to the ~~implementation of a revised~~ Basic Service ~~rate~~Adder but instructed NSTAR Electric to reduce distribution rates by an ~~amount~~ equal ~~to the increase in its Basic Service bad debt charge-offs.~~and offsetting amount. This adjustment to NSTAR Electric's distribution rates would ~~eliminate~~have eliminated 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. NSTAR Electric took the position that it had fully removed the collection of energy-related bad debt costs from its base distribution rates effective January 1, 2006; therefore, no further adjustment to distribution rates was warranted. 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.~~

On January 7, 2015, the DPU issued an order concluding that NSTAR Electric ~~deferred approximately $34 million~~had appropriately accounted for the removal of supply-related bad debt costs ~~associated with~~from base distribution rates effective January 1, 2006. The DPU ordered NSTAR Electric and the Massachusetts Attorney General to collaborate on the reconciliation of energy-related bad debt costs through 2014. During the second quarter of 2015, NSTAR Electric expects to file with the DPU to recover from customers approximately $43 million of supply-related bad debt costs. In the first quarter of 2015, as a ~~regulatory asset through 2011 as~~result of the DPU order, NSTAR Electric ~~had concluded that it was probable that these costs would ultimately be recovered from customers. Due to the delays~~increased its regulatory assets and ~~the duration~~reduced Operations and Maintenance expense by $24.2 million, resulting in an increase in after-tax earnings 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.$14.5 million.

F.
34PSNH Generation Restructuring
On March 11, 2015, PSNH and key New Hampshire officials entered into an agreement in principle in a settlement Term Sheet. Under the Term Sheet, PSNH has agreed to pursue the divestiture of its generation assets upon NHPUC approval of a final Settlement Agreement reflecting the provisions of the Term Sheet, and PSNH will not seek a general distribution rate increase that would become effective before July 1, 2017. PSNH will contribute $5 million to create a clean energy fund, which will not be recoverable from its customers, and will record this liability and related charge upon completion of the Settlement Agreement.

9.
FAIR VALUE OF FINANCIAL INSTRUMENTS

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

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

As of June 30, 2014

As of December 31, 2013

As of March, 31, 2015

As of December 31, 2014

NU

NU

ES

ES

Carrying

Fair

Carrying

Fair

Carrying

Fair

Carrying

Fair
(Millions of Dollars)
(Millions of Dollars)
Amount

Value

Amount

Value
(Millions of Dollars)
Amount

Value

Amount

Value
Preferred Stock Not
Subject to Mandatory Redemption
Preferred Stock Not
Subject to Mandatory Redemption
$
155.6

$
150.1

$
155.6

$
152.7
Preferred Stock Not
Subject to Mandatory Redemption
$
155.6

$
155.1

$
155.6

$
153.6
Long-Term Debt
Long-Term Debt

8,542.7

9,008.4

8,310.2

8,443.1
Long-Term Debt

8,847.7

9,553.1

8,851.6

9,451.2

As of June 30, 2014

As of March 31, 2015

CL&P

NSTAR Electric

PSNH

WMECO

CL&P

NSTAR Electric

PSNH

WMECO

Carrying

Fair

Carrying

Fair

Carrying

Fair

Carrying

Fair

Carrying

Fair

Carrying

Fair

Carrying

Fair

Carrying

Fair
(Millions of Dollars)
(Millions of Dollars)
Amount

Value

Amount

Value

Amount

Value

Amount

Value
(Millions of Dollars)
Amount

Value

Amount

Value

Amount

Value

Amount

Value
Preferred Stock Not
Subject to Mandatory Redemption
Preferred Stock Not
Subject to Mandatory Redemption
$
116.2

$
110.3

$
43.0

$
39.8

$
-

$
-

$
-

$
-
Preferred Stock Not
Subject to Mandatory Redemption
$
116.2

$
113.0

$
43.0

$
42.1

$
-

$
-

$
-

$
-
Long-Term Debt
Long-Term Debt

2,991.6

3,344.5

1,797.4

1,949.8

1,049.2

1,105.8

628.9

665.3
Long-Term Debt

2,842.1

3,260.4

1,797.4

2,022.1

1,076.3

1,156.4

628.2

674.4

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

26

As of December 31, 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

$
112.0

$
43.0

$
41.6

$
-

$
-

$
-

$
-
Long-Term Debt

2,842.0

3,214.5

1,797.4

1,993.5

1,076.3

1,137.9

628.5

689.4

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

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

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

10.
ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)

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

For the Six Months Ended June 30, 2014

For the Six Months Ended June 30, 2013

Unrealized

Pension,

Unrealized

Pension,

For the Three Months Ended March 31, 2015

For the Three Months Ended March 31, 2014

Qualified

Gains/(Losses)

SERP and

Qualified

Gains/(Losses)

SERP and

Qualified

Unrealized

Qualified

Unrealized

Cash Flow

on Available-

PBOP

Cash Flow

on Available-

PBOP

Cash Flow

Gains on

Defined

Cash Flow

Gains on

Defined

Hedging

for-Sale

Benefit

Hedging

for-Sale

Benefit

Hedging

Marketable

Benefit

Hedging

Marketable

Benefit

(Millions of Dollars)
(Millions of Dollars)
Instruments

Securities

Plans

Total

Instruments

Securities

Plans

Total
(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)
Balance as of Beginning of Period
Balance as of Beginning of Period
$
(12.4)

$
0.7

$
(62.3)

$
(74.0)

$
(14.4)

$
0.4

$
(32.0)

$
(46.0)

OCI Before Reclassifications
OCI Before Reclassifications

-

0.5

1.2

1.7

-

(0.7)

-

(0.7)
OCI Before Reclassifications

-

0.1

-

0.1

-

0.2

-

0.2
Amounts Reclassified from AOCI
Amounts Reclassified from AOCI

1.0

-

1.8

2.8

1.0

-

3.1

4.1
Amounts Reclassified from AOCI

0.5

-

1.0

1.5

0.5

-

1.0

1.5
Net OCI
Net OCI

1.0

0.5

3.0

4.5

1.0

(0.7)

3.1

3.4
Net OCI

0.5

0.1

1.0

1.6

0.5

0.2

1.0

1.7
AOCI as of End of Period
$
(13.4)

$
0.9

$
(29.0)

$
(41.5)

$
(15.4)

$
0.6

$
(54.7)

$
(69.5)
Balance as of End of Period
Balance as of End of Period
$
(11.9)

$
0.8

$
(61.3)

$
(72.4)

$
(13.9)

$
0.6

$
(31.0)

$
(44.3)

~~NU's~~Eversource'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.

35

The ~~following table sets forth~~amortization expense of actuarial gains and losses on the defined benefit plans is amortized from AOCI into Operations and Maintenance over the average future employee service period, and are reflected in amounts reclassified from ~~AOCI by component~~AOCI. The related tax effects of the reclassification adjustments are not material to the financial statements for the three months ended March 31, 2015 and ~~the impacted line item on the statements of income:~~

For the Three Months Ended

For the Six Months Ended

June 30,

June 30,

Amounts Reclassified

Amounts Reclassified

Statements of Income

from AOCI

from AOCI

Line Item Impacted
(Millions of Dollars)
2014

2013

2014

2013

Qualified Cash Flow Hedging Instruments
$
(0.8)

$
(0.8)

$
(1.7)

$
(1.7)

Interest Expense
Tax Benefit

0.3

0.3

0.7

0.7

Income Tax Expense
Qualified Cash Flow Hedging Instruments, Net of Tax
$
(0.5)

$
(0.5)

$
(1.0)

$
(1.0)

Pension, SERP and PBOP Benefit Plan Costs:

   Amortization of Actuarial Losses
$
(1.2)

$
(2.2)

$
(2.9)

$
(4.7)

Operations and Maintenance⁽¹⁾
   Amortization of Prior Service Cost

-

-

(0.1)

(0.1)

Operations and Maintenance⁽¹⁾
Total Pension, SERP and PBOP Benefit Plan Costs

(1.2)

(2.2)

(3.0)

(4.8)

Tax Benefit

0.5

0.7

1.2

1.7

Income Tax Expense
Pension, SERP and PBOP Benefit Plan Costs, Net of Tax
$
(0.7)

$
(1.5)

$
(1.8)

$
(3.1)

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

$
(2.0)

$
(2.8)

$
(4.1)

⁽¹⁾
~~These amounts are included in the computation of net periodic Pension, SERP and PBOP costs. See Note 7, "Pension Benefits and Postretirement Benefits Other Than Pensions," for further information.~~2014.

11.
COMMON SHARES

The following table sets forth the NUES parent 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
Shares

Authorized as of

Authorized as of

Per Share

June 30, 2014 and

Issued as of
Per Share

March 31, 2015 and

Issued as of

Par Value

December 31, 2013

June 30, 2014

December 31, 2013
Par Value

December 31, 2014

March 31, 2015

December 31, 2014
NU
$
5

380,000,000

333,327,485

333,113,492
ES
$
5

380,000,000

333,607,844

333,359,172
CL&P
$
10

24,500,000

6,035,205

6,035,205
$
10

24,500,000

6,035,205

6,035,205
NSTAR Electric
$
1

100,000,000

100

100
$
1

100,000,000

100

100
PSNH
$
1

100,000,000

301

301
$
1

100,000,000

301

301
WMECO
$
25

1,072,471

434,653

434,653
$
25

1,072,471

434,653

434,653

As of ~~June 30, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, there were ~~17,108,131~~16,138,845 and ~~17,796,672 NU~~16,375,835 Eversource common shares held as treasury shares, respectively. As of ~~June 30, 2014~~March 31, 2015 and December 31, ~~2013, NU~~2014, Eversource common shares outstanding were ~~316,219,354~~317,468,999 and ~~315,273,559,~~316,983,337, respectively.

12.
COMMON SHAREHOLDERS' EQUITY AND NONCONTROLLING INTERESTS

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

For the Three Months Ended

June 30, 2014

June 30, 2013

Noncontrolling

Noncontrolling

Interest -

Interest -

Common

Preferred

Common

Preferred

Shareholders'

Stock of

Shareholders'

Stock of

(Millions of Dollars)
Equity

Subsidiaries

Equity

Subsidiaries

Balance as of Beginning of Period
$
9,723.9

$
155.6

$
9,345.2

$
155.6

Net Income

129.2

-

173.1

-

Dividends on Common Shares

(124.1)

-

(115.6)

-

Dividends on Preferred Stock

(1.9)

(1.9)

(2.0)

(2.0)

Issuance of Common Shares

0.2

-

0.3

-

Other Transactions, Net

23.7

-

4.2

-

Net Income Attributable to Noncontrolling Interests

-

1.9

-

2.0

Other Comprehensive Income

2.8

-

1.4

-

Balance as of End of Period
$
9,753.8

$
155.6

$
9,406.6

$
155.6

12.
COMMON SHAREHOLDERS' EQUITY AND NONCONTROLLING INTERESTS

For the three months ended March 31, 2015 and 2014, there were dividends on the preferred stock of CL&P and NSTAR Electric of $1.9 million, which were presented as Net Income Attributable to Noncontrolling Interests on the Eversource statements of income. Common Shareholders' Equity was fully attributable to the parent and Noncontrolling Interest – Preferred Stock of Subsidiaries was fully attributable to the noncontrolling interest on the Eversource balance sheets.

3627

For the Six Months Ended

June 30, 2014

June 30, 2013

Noncontrolling

Noncontrolling

Interest -

Interest -

Common

Preferred

Common

Preferred

Shareholders'

Stock of

Shareholders'

Stock of

(Millions of Dollars)
Equity

Subsidiaries

Equity

Subsidiaries

Balance as of Beginning of Period
$
9,611.5

$
155.6

$
9,237.1

$
155.6

Net Income

367.1

-

403.0

-

Dividends on Common Shares

(247.9)

-

(232.1)

-

Dividends on Preferred Stock

(3.8)

(3.8)

(3.9)

(3.9)

Issuance of Common Shares

5.4

-

8.8

-

Other Transactions, Net

17.0

-

(9.7)

-

Net Income Attributable to Noncontrolling Interests

-

3.8

-

3.9

Other Comprehensive Income

4.5

-

3.4

-

Balance as of End of Period
$
9,753.8

$
155.6

$
9,406.6

$
155.6

13.
EARNINGS PER SHARE

Basic EPS is computed based upon the weighted average number of common shares outstanding during each period. Diluted EPS is computed on the basis of the weighted average number of common shares outstanding plus the potential dilutive effect of certain share-based compensation awards as if they were converted into common shares. ~~There were no antidilutive share awards outstanding for the three and six months ended June 30, 2014 or for~~For the three months ended ~~June 30, 2013. For the six months ended June 30, 2013,~~March 31, 2015 and 2014, there were ~~3,150~~no antidilutive share awards excluded from the computation.

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

For the Three Months Ended

For the Six Months Ended

For the Three Months Ended
(Millions of Dollars, except share information)
(Millions of Dollars, except share information)
June 30, 2014

June 30, 2013

June 30, 2014

June 30, 2013
(Millions of Dollars, except share information)
March 31, 2015

March 31, 2014
Net Income Attributable to Controlling Interest
Net Income Attributable to Controlling Interest
$
127.4

$
171.0

$
363.3

$
399.1
Net Income Attributable to Controlling Interest
$
253.3

$
236.0

Weighted Average Common Shares Outstanding:
Weighted Average Common Shares Outstanding:

Weighted Average Common Shares Outstanding:

Basic

315,950,510

315,154,130

315,742,511

315,141,956
Basic

317,090,841

315,534,512

Dilutive Effect

1,162,291

808,489

1,259,950

840,622
Dilutive Effect

1,400,347

1,357,607

Diluted

317,112,801

315,962,619

317,002,461

315,982,578
Diluted

318,491,188

316,892,119
Basic EPS
Basic EPS
$
0.40

$
0.54

$
1.15

$
1.27
Basic EPS
$
0.80

$
0.75
Diluted EPS
Diluted EPS
$
0.40

$
0.54

$
1.15

$
1.26
Diluted EPS
$
0.80

$
0.74

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

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

14.
SEGMENT INFORMATION

Presentation: NUEversource 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~~Eversource's total consolidated revenues for the three ~~and six~~ months ended ~~June 30, 2014~~March 31, 2015 and ~~2013.~~2014. 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~~Eversource's operations is presented as Other in the tables below and primarily consists of 1) the equity in earnings of NUES parent from its subsidiaries and intercompany interest income, both of which are eliminated in consolidation, and interest expense related to the debt of NUES parent, 2) the revenues and expenses of ~~NU's service company,~~Eversource Service, most of which are eliminated in consolidation, 3) the operations of CYAPC and YAEC, and 4) the results of other ~~non-regulated~~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~~Eversource's reportable segments are determined based upon the level at which ~~NU's~~Eversource's chief operating decision maker assesses performance and makes decisions about the allocation of company resources. Each of ~~NU's~~Eversource's subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, has one reportable segment. ~~NU's~~Eversource's operating segments and reporting units are consistent with its reportable business segments.

37

~~NU's~~Eversource's segment information is as follows:

For the Three Months Ended June 30, 2014

Electric

Natural Gas

(Millions of Dollars)
Distribution

Distribution

Transmission

Other

Eliminations

Total
Operating Revenues
$
1,261.8

$
195.5

$
206.9

$
184.7

$
(171.3)

$
1,677.6
Depreciation and Amortization

(89.3)

(16.9)

(37.0)

(7.7)

2.3

(148.6)
Other Operating Expenses

(991.5)

(166.5)

(71.0)

(174.9)

168.9

(1,235.0)
Operating Income

181.0

12.1

98.9

2.1

(0.1)

294.0
Interest Expense

(47.2)

(8.7)

(28.8)

(9.1)

1.3

(92.5)
Other Income, Net

2.9

-

2.7

137.7

(137.8)

5.5
Net Income Attributable to Controlling Interest
$
83.4

$
2.0

$
43.9

$
133.3

$
(135.2)

$
127.4

For the Six Months Ended June 30, 2014

Electric

Natural Gas

(Millions of Dollars)
Distribution

Distribution

Transmission

Other

Eliminations

Total
Operating Revenues
$
2,847.8

$
628.3

$
458.9

$
356.9

$
(323.7)

$
3,968.2
Depreciation and Amortization

(238.2)

(34.6)

(74.0)

(14.7)

4.1

(357.4)
Other Operating Expenses

(2,202.4)

(487.9)

(137.3)

(340.3)

318.8

(2,849.1)
Operating Income

407.2

105.8

247.6

1.9

(0.8)

761.7
Interest Expense

(94.6)

(17.1)

(54.3)

(18.7)

2.2

(182.5)
Other Income, Net

4.3

0.1

4.2

432.4

(433.8)

7.2
Net Income Attributable to Controlling Interest
$
195.6

$
54.1

$
118.8

$
424.9

$
(430.1)

$
363.3
Cash Flows Used for Investments in Plant
$
335.6

$
68.6

$
289.3

$
30.5

$
-

$
724.0

For the Three Months Ended June 30, 2013

Electric

Natural Gas

(Millions of Dollars)
Distribution

Distribution

Transmission

Other

Eliminations

Total
Operating Revenues
$
1,221.6

$
154.1

$
247.9

$
220.7

$
(208.4)

$
1,635.9
Depreciation and Amortization

(152.2)

(16.7)

(34.5)

(21.7)

2.9

(222.2)
Other Operating Expenses

(883.3)

(127.0)

(63.6)

(194.9)

205.7

(1,063.1)
Operating Income

186.1

10.4

149.8

4.1

0.2

350.6
Interest Expense

(43.4)

(8.9)

(25.2)

(10.7)

1.3

(86.9)
Other Income, Net

2.2

0.1

2.8

232.2

(232.3)

5.0
Net Income Attributable to Controlling Interest
$
91.2

$
1.2

$
76.8

$
232.8

$
(231.0)

$
171.0

For the Six Months Ended June 30, 2013

Electric

Natural Gas

(Millions of Dollars)
Distribution

Distribution

Transmission

Other

Eliminations

Total
Operating Revenues
$
2,595.8

$
515.9

$
487.4

$
437.8

$
(406.0)

$
3,630.9
Depreciation and Amortization

(329.1)

(34.1)

(66.3)

(40.8)

4.6

(465.7)
Other Operating Expenses

(1,888.3)

(394.3)

(125.8)

(392.2)

404.9

(2,395.7)
Operating Income

378.4

87.5

295.3

4.8

3.5

769.5
Interest Expense

(85.6)

(16.2)

(47.1)

(17.1)

2.9

(163.1)
Other Income, Net

7.1

0.3

5.5

554.0

(554.2)

12.7
Net Income Attributable to Controlling Interest
$
190.6

$
44.5

$
156.7

$
555.5

$
(548.2)

$
399.1
Cash Flows Used for Investments in Plant
$
315.3

$
70.9

$
297.4

$
16.7

$
-

$
700.3

The following table summarizes NU's segmented total assets:

Electric

Natural Gas

(Millions of Dollars)
Distribution

Distribution

Transmission

Other

Eliminations

Total
As of June 30, 2014
$
16,942.5

$
2,753.8

$
6,934.1

$
11,566.6

$
(10,406.6)

$
27,790.4
As of December 31, 2013

17,260.0

2,759.7

6,745.8

11,842.4

(10,812.4)

27,795.5

For the Three Months Ended March 31, 2015

Electric

Natural Gas

(Millions of Dollars)
Distribution

Distribution

Transmission

Other

Eliminations

Total
Operating Revenues
$
1,760.1

$
507.4

$
249.0

$
240.0

$
(243.1)

$
2,513.4
Depreciation and Amortization

(159.1)

(18.2)

(40.4)

(7.2)

0.5

(224.4)
Other Operating Expenses

(1,342.8)

(388.5)

(74.1)

(229.2)

243.1

(1,791.5)
Operating Income

258.2

100.7

134.5

3.6

0.5

497.5
Interest Expense

(47.6)

(9.0)

(27.6)

(11.8)

1.2

(94.8)
Other Income/(Loss), Net

2.2

(0.2)

2.9

314.9

(314.1)

5.7
Net Income Attributable to Controlling Interest
$
130.6

$
55.6

$
66.6

$
312.9

$
(312.4)

$
253.3
Cash Flows Used for Investments in Plant
$
172.5

$
30.0

$
150.0

$
10.1

$
-

$
362.6

3828

For the Three Months Ended March 31, 2014

Electric

Natural Gas

(Millions of Dollars)
Distribution

Distribution

Transmission

Other

Eliminations

Total
Operating Revenues
$
1,585.9

$
432.8

$
252.1

$
172.2

$
(152.4)

$
2,290.6
Depreciation and Amortization

(148.8)

(17.7)

(37.0)

(7.0)

1.8

(208.7)
Other Operating Expenses

(1,210.9)

(321.4)

(66.4)

(165.4)

149.9

(1,614.2)
Operating Income/(Loss)

226.2

93.7

148.7

(0.2)

(0.7)

467.7
Interest Expense

(47.4)

(8.5)

(25.5)

(9.6)

1.0

(90.0)
Other Income, Net

1.4

0.1

1.5

294.8

(296.1)

1.7
Net Income Attributable to Controlling Interest
$
112.2

$
52.1

$
74.9

$
291.7

$
(294.9)

$
236.0
Cash Flows Used for Investments in Plant
$
189.4

$
28.9

$
112.2

$
18.2

$
-

$
348.7

The following table summarizes Eversource's segmented total assets:

Electric

Natural Gas

(Millions of Dollars)
Distribution

Distribution

Transmission

Other

Eliminations

Total
As of March 31, 2015
$
17,930.2

$
3,008.5

$
7,503.1

$
12,874.1

$
(11,364.1)

$
29,951.8
As of December 31, 2014

17,563.4

3,030.9

7,625.6

12,682.5

(11,124.4)

29,778.0
~~NORTHEAST UTILITIES~~

29

EVERSOURCE ENERGY AND SUBSIDIARIES

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

The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements and related combined notes included in this combined Quarterly Report on Form 10-Q ~~the First Quarter 2014 Form 10-Q,~~ and the ~~2013~~2014 Annual Report on Form 10-K. References in this Form 10-Q to ~~"NU,~~"Eversource," the "Company," "we," "us," and "our" refer to ~~Northeast Utilities~~Eversource and its consolidated subsidiaries. All per share amounts are reported on a diluted basis. The unaudited condensed consolidated financial statements of ~~NU,~~Eversource, 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 thisManagement'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.~~Eversource. The earnings and EPS of each business discussed below do not represent a direct legal interest in the assets and liabilities ~~allocated to~~of 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 NUEversource common shares outstanding for the ~~year.~~period. The discussion below also includes non-GAAP financial measures referencing our ~~second~~first quarter 2015 and ~~first half of~~ 2014 ~~and 2013~~ earnings and EPS excluding certain integration costs related to ~~NU's~~our merger with NSTAR. We use these non-GAAP financial measures to evaluate and to provide details of earnings by business and to more fully compare and explain our ~~second~~first quarter 2015 and ~~first half of~~ 2014 ~~and 2013~~ results without including the impact of these ~~non-recurring~~ items. Due to the nature and significance of these items on Net Income Attributable to Controlling Interest, we believe that the non-GAAP presentation is more representative of our financial performance and provides additional and useful information to readers of this report in analyzing historical and future performance by business. These non-GAAP financial measures should not be considered as an alternative to reported Net Income Attributable to Controlling Interest or EPS determined in accordance with GAAP as an indicator of operating performance.

Reconciliations of the above non-GAAP financial measures to the most directly comparable GAAP measures of consolidated diluted EPS and Net Income Attributable to Controlling Interest are included under "Financial Condition and Business Analysis – Overview – Consolidated" and "Financial Condition and Business Analysis – Overview – Regulated Companies" inManagement'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, public policy 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, which could include disruptive technology related to our current or future business model,
^·
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~~Eversource's 2014 combined Annual Report on Form 10-K. This Quarterly Report on Form 10-Q and ~~NU's 2013~~Eversource's 2014 combined Annual Report on Form 10-K also ~~describe~~describes material contingencies and critical accounting policies in the accompanyingManagement's Discussion and Analysis of Financial Condition and Results of OperationsandCombined Notes to Condensed Consolidated Financial Statements (Unaudited). We encourage you to review these items.

3930

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:

The earnings discussion below compares the first quarter of 2015 with the first quarter of 2014:

·
We earned ~~$127.4~~$253.3 million, or ~~$0.40~~$0.80 per share, ~~in the second quarter of 2014, and $363.3~~compared with $236 million, or ~~$1.15~~$0.74 per ~~share, in the first half of 2014, compared with $171 million, or $0.54 per share, in the second quarter of 2013 and $399.1 million, or $1.26 per share, in the first half of 2013.~~share. Excluding integration costs, we earned ~~$131.9~~$257.3 million, or ~~$0.42~~$0.81 per share, ~~in the second quarter of 2014, and $373.7~~compared with $241.8 million, or ~~$1.18~~$0.76 per ~~share, in the first half of 2014, compared with $172.8 million, or $0.55 per share, in the second quarter of 2013, and $402.6 million, or $1.27 per share, in the first half of 2013.~~share.

·
Our electric distribution segment, which includes generation, earned ~~$83.4~~$130.6 million, or ~~$0.26~~$0.41 per share, ~~in the second quarter of 2014 and $195.6~~compared with $112.2 million, or ~~$0.62~~$0.35 per ~~share, in the first half of 2014, compared with earnings of $91.2 million, or $0.29 per share, in the second quarter of 2013 and $190.6 million, or $0.60 per share, in the first half of 2013.~~

·
share. Our transmission segment earned ~~$43.9~~$66.6 million, or ~~$0.14~~$0.21 per share, ~~in the second quarter of 2014 and $118.8~~compared with $74.9 million, or ~~$0.37~~$0.24 per share, in the first half of 2014, compared with $76.8 million, or $0.25 per share, in the second quarter of 2013 and $156.7 million, or $0.50 per share, in the first half of 2013. The decrease in the second quarter and first half of 2014 earnings, as compared to the same periods in 2013, was due primarily to the establishment of a $32.1 million after-tax reserve related to FERC ROE orders issued on June 19, 2014.

·
share. Our natural gas distribution segment earned $2$55.6 million, or ~~$0.01~~$0.18 per share, ~~in the second quarter of 2014 and $54.1~~compared with $52.1 million, or ~~$0.17~~$0.16 per ~~share, in the first half of 2014, compared with $1.2 million in the second quarter of 2013 and $44.5 million, or $0.14 per share, in the first half of 2013.~~share.

·
NUES parent and other companies had net earnings of $0.5 million, compared with net losses of ~~$1.9~~$3.2 million, or $0.01 per share. The 2015 and 2014 results reflect $4 million, or $0.01 per share, ~~in the second quarter of 2014~~ and ~~$5.2 million, or $0.01 per share, in the first half of 2014, compared with earnings of $1.8 million in the second quarter of 2013 and $7.3~~$5.8 million, or $0.02 per share, ~~in the first half of 2013. Second quarter and first half 2014 results reflect $4.5 million and $10.4 million,~~ respectively, of ~~after-tax~~ integration costs. ~~Second quarter and first half 2013 results reflect $1.8 million and $3.5 million, respectively, of after-tax integration costs.~~

Legislative, Regulatory, Policy and ~~Regulatory~~Other Items:

·
On ~~June 9, 2014, CL&P filed~~January 7, 2015, the DPU issued an ~~application~~order concluding that NSTAR Electric had appropriately accounted for the removal of supply-related bad debt costs from base distribution rates effective January 1, 2006. The DPU ordered NSTAR Electric and the Massachusetts Attorney General to collaborate on the reconciliation of energy-related bad debt costs through 2014. During the second quarter of 2015, NSTAR Electric expects to file with the ~~PURA~~DPU to ~~amend customer rates, effective December 1, 2014. CL&P requested~~recover from customers approximately $43 million of supply-related bad debt costs. In the first quarter of 2015, as a result of the January 7^th DPU order, NSTAR Electric increased its regulatory assets by $24.2 million, resulting in an increase in ~~base distribution rates~~after-tax earnings of ~~$116.7~~$14.5 million. ~~Based on the current schedule, we expect a final decision in December 2014.~~

·
On ~~June 19, 2014,~~March 2, 2015, the DPU approved a comprehensive settlement agreement between NSTAR Electric, NSTAR Gas and the Massachusetts Attorney General (the "Settlement") as filed with the DPU on December 31, 2014. The Settlement resolved the outstanding NSTAR Electric CPSL program filings, the NSTAR Electric and NSTAR Gas PAM and energy efficiency-related customer billing adjustments, and the recovery of LBR related to NSTAR Electric’s energy efficiency programs (11 dockets in total). As a result, NSTAR Electric and NSTAR Gas will refund a combined $44.7 million to customers, which was recorded as a regulatory liability as of March 31, 2015, and recognized a $13 million after-tax benefit in the first quarter of 2015.

·
On March 3, 2015, FERC issued ~~two orders~~an order denying all issues raised on rehearing by the NETOs and Complainants in the ~~pending~~first base ROE complaint proceedings. The first order addressed the joint complaint filed at FERC in September 2011 by several New England parties alleging that the base ROE of 11.14 percent was unjust and unreasonable.complaint. The FERC ~~set a single tentative~~order upheld our base ROE of 10.57 percent ~~for the refund period (October 1, 2011 through December 31, 2012)~~ and ~~the prospective period (beginning when FERC finalizes the base ROE). The second order addressed a second joint complaint filed at FERC in December 2012 by additional New England parties alleging~~upheld that the ~~base~~utilities total ROE ~~was unjust and unreasonable. The complaint sought refunds for~~is capped at the ~~15-month period beginning January 1, 2013. The FERC found that~~top of the ~~second complaint raised issues~~zone of ~~material fact and~~reasonableness, which is currently set ~~this complaint for settlement or trial if settlement negotiations should be unsuccessful. We recorded~~at 11.74 percent. As a ~~series~~result of ~~reserves totaling $32.1 million~~clarifying information related to how the ROE cap is applied, which is contained in the order, we recognized an after-tax ~~at our electric subsidiaries~~charge to ~~recognize the potential financial impact from the FERC's two orders for the two refund periods.~~earnings of $12.4 million.

·
On ~~July 7, 2014, Massachusetts enacted "An Act Relative~~March 11, 2015, PSNH and key New Hampshire officials entered into an agreement in principle in a settlement Term Sheet (Term Sheet) designed to ~~Natural Gas Leaks" (the Act)~~provide a resolution of issues pertaining to PSNH’s generation assets in pending regulatory proceedings. PSNH has agreed to pursue the divestiture of its generation assets upon NHPUC approval of a final Settlement Agreement reflecting the provisions of the Term Sheet (Settlement Agreement). ~~The Act establishes~~As part of the planned Settlement Agreement, PSNH has agreed to forego recovery of $25 million of the deferred equity return related to the Clean Air Project. Upon completion of the divestiture process, all costs not recovered from sales proceeds (stranded costs), will be recovered via bonds that will be secured by a ~~uniform natural gas leak classification standard for all Massachusetts natural gas utilities~~non-bypassable charge to PSNH's customers. Consummation of the Term Sheet provisions is conditioned upon the enactment of New Hampshire legislation, completion of the Settlement Agreement, and NHPUC approval of the Settlement Agreement. We expect legislation to be finalized in the third quarter of 2015 and a ~~program that accelerates the replacement of aging natural gas infrastructure. The Act also calls for the DPU~~NHPUC decision 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.~~be issued in late 2015.

Liquidity:

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

·
Cash flows provided by operating activities totaled ~~$896.7~~$481.8 million in the first ~~half~~quarter of ~~2014,~~2015, compared with ~~$769~~$493.8 million in the first ~~half~~quarter of ~~2013. The improved operating cash flows were due primarily to approximately $126~~2014. Investments in property, plant and equipment totaled $362.6 million in DOE Phase II proceeds received by CL&P, NSTAR Electric, PSNH and WMECO on June 1, 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, the absence of cash disbursements for major storm restoration costs and the decrease of $82.2 million in Pension and PBOP Plan cash contributions, partially offset by an increase in income taxes paid in the first ~~half~~quarter of ~~2014 ($158 million), as~~2015, compared towith $348.7 million in the first ~~half~~quarter of ~~2013 ($16 million).~~2014. Cash and cash equivalents totaled $71 million as of March 31, 2015, compared with $38.7 million as of December 31, 2014.

·
~~In the first half of 2014, we~~On January 15, 2015, ES parent issued ~~$650~~$150 million of ~~new long-term debt consisting of $100 million by Yankee Gas on January 2, 2014,~~1.60 percent Series G Senior Notes, due to mature in 2018 and $300 million ~~by NSTAR Electric on March 7, 2014, and $250 million by CL&P on April 24, 2014. These new issuances~~of 3.15 percent Series H Senior Notes, due to mature in 2025. Proceeds were used to repay ~~approximately $375 million of existing long-term debt with~~short-term borrowings outstanding under the ~~remainder used to pay short-term borrowings.~~ ES parent commercial paper program.

40

·
~~In the first half of 2014, we had cash dividends on common shares of $237.2 million, compared with $232 million in the first half of 2013.~~ On ~~May 1, 2014,~~April 29, 2015, our Board of Trustees approved a common share dividend payment of ~~$0.3925~~$0.4175 per share, ~~which was paid~~payable on June 30, ~~2014~~2015 to shareholders of record as of May ~~30, 2014.~~ 29, 2015.

31

Overview

Consolidated: A summary of our earnings by business, which also reconciles the non-GAAP financial measures of consolidated non-GAAP earnings and EPS, as well as EPS by business, to the most directly comparable GAAP measures of consolidated Net Income Attributable to Controlling Interest and diluted EPS, for the ~~second quarter~~first quarters of 2015 and ~~first half of~~ 2014 ~~and 2013~~ is as follows:

For the Three Months Ended June 30,

For the Six Months Ended June 30,
(Millions of Dollars, Except

2014

2013

2014

2013
  Per Share Amounts)

Amount

Per Share

Amount

Per Share

Amount

Per Share

Amount

Per Share
Net Income Attributable to
  Controlling Interest (GAAP)

$
127.4

$
0.40

$
171.0

$
0.54

$
363.3

$
1.15

$
399.1

$
1.26

Regulated Companies

$
129.3

$
0.41

$
169.2

$
0.54

$
368.5

$
1.16

$
391.8

$
1.24
NU Parent and Other Companies

2.6

0.01

3.6

0.01

5.2

0.02

10.8

0.03
Non-GAAP Earnings

131.9

0.42

172.8

0.55

373.7

1.18

402.6

1.27
Integration Costs (after-tax)

(4.5)

(0.02)

(1.8)

(0.01)

(10.4)

(0.03)

(3.5)

(0.01)
Net Income Attributable to
  Controlling Interest (GAAP)

$
127.4

$
0.40

$
171.0

$
0.54

$
363.3

$
1.15

$
399.1

$
1.26

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

For the Three Months Ended March 31,

2015

2014
(Millions of Dollars, Except Per Share Amounts)

Amount

Per Share

Amount

Per Share
Net Income Attributable to Controlling Interest (GAAP)

$
253.3

$
0.80

$
236.0

$
0.74

Regulated Companies

$
252.8

$
0.80

$
239.2

$
0.75
ES Parent and Other Companies

4.5

0.01

2.6

0.01
Non-GAAP Earnings

257.3

0.81

241.8

0.76
Integration Costs (after-tax)

(4.0)

(0.01)

(5.8)

(0.02)
Net Income Attributable to Controlling Interest (GAAP)

$
253.3

$
0.80

$
236.0

$
0.74

Excluding the impact of integration costs, our first ~~half 2014~~quarter 2015 earnings ~~decreased~~increased by ~~$28.9~~$15.5 million, as compared to the first half of 2013, due primarily to the establishment of the $32.1 million after-tax reserve related to June 2014 FERC base ROE orders, the absence of a favorable impact from the resolution of a state income tax audit in the first quarter of 2013, and higher depreciation expense and property taxes. Earnings were favorably impacted by higher retail electric and firm natural gas sales as a result of the colder weather in the first quarter of 2014, as compared to the first quarter of ~~2013,~~2014. The increase was due primarily to the $27.5 million favorable earnings impact related to the resolution of NSTAR Electric’s basic service bad debt adder, the CPSL program filings, and ~~lower general~~the recovery of LBR related to energy efficiency programs, and ~~administrative costs.~~ the impact of the December 1, 2014 CL&P base distribution rate increase. Partially offsetting these favorable earnings impacts were the $12.4 million after-tax reserve related to the March 2015 FERC ROE order, an increase in operations and maintenance costs primarily attributable to an increase in labor and employee benefits expense, as a result of the impact from winter weather and storms, as compared to the first quarter of 2014, higher depreciation expense and higher property taxes.

The first quarter 2015 and 2014 integration costs included costs incurred for employee severance in connection with ongoing integration. In addition, the first quarter 2015 integration costs also included costs associated with our branding efforts.

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 ~~second quarter~~first quarters of 2015 and ~~first half of~~ 2014 ~~and 2013~~ is as follows:

For the Three Months
Ended June 30,

For the Six Months
Ended June 30,

For the Three Months Ended March 31,
(Millions of Dollars)
2014

2013

2014

2013

2015

2014
(Millions of Dollars, Except Per Share Amounts)

Amount

Per Share

Amount

Per Share
Electric Distribution
$
83.4

$
91.2

$
195.6

$
190.6

$
130.6

$
0.41

$
112.2

$
0.35
Transmission

43.9

76.8

118.8

156.7

66.6

0.21

74.9

0.24
Natural Gas Distribution

2.0

1.2

54.1

44.5

55.6

0.18

52.1

0.16
Net Income - Regulated Companies
$
129.3

$
169.2

$
368.5

$
391.8

$
252.8

$
0.80

$
239.2

$
0.75

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

~~Our electric~~Ourelectric distribution segment earnings increased $5$18.4 million ~~in the first half of 2014, as compared to the first half of 2013, due primarily to higher retail electric sales as a result of the colder weather~~ in the first quarter of ~~2014,~~2015, as compared to the first quarter of ~~2013,~~2014, due primarily to the $27.5 million favorable earnings impact related to the resolution of NSTAR Electric’s basic service bad debt adder, the CPSL program filings, and ~~a decrease~~the recovery of LBR related to energy efficiency programs, and the impact of the December 1, 2014 CL&P base distribution rate increase. Partially offsetting these favorable earnings impacts were an increase in operations and maintenance costs ~~that~~primarily attributable to an increase in labor and employee benefits expense, as a result of the impact ~~earnings. Partially offsetting these favorable impacts were~~from winter weather and storms, as compared to the ~~absence~~first quarter of ~~regulatory interest income from stranded cost recoveries in 2013,~~2014, higher depreciation expense and higher ~~depreciation and~~ property ~~tax expense.~~taxes.

Our transmission segment earnings decreased ~~$32.9~~$8.3 million in the ~~second~~first quarter of ~~2014,~~2015, as compared to the ~~second~~first quarter of ~~2013,~~2014, due primarily to the ~~establishment of the $32.1~~$12.4 million after-tax reserve related to the ~~June 2014~~March 2015 FERC ROE ~~orders,~~order and the ~~net unfavorable~~negative earnings impact on transmission revenues as a result of a refund to our customers in June 2014, partially offset by a higher transmission rate base as a result of an increased investment in our transmission infrastructure.

~~Our transmission segment earnings decreased $37.9 million~~resulting from the lower allowed ROE in the first ~~half~~quarter of ~~2014,~~2015, as compared to the first half of 2013, due primarily to the $32.1 million after-tax reserve related to the June 2014 FERC ROE orders, the absence of the favorable impact from the resolution of the state income tax audit in the first quarter of ~~2013, the net unfavorable impact on transmission revenues as a result of a refund to our customers in June~~ 2014, partially offset by a higher transmission rate base as a result of an increased investment in our transmission infrastructure.

Our natural gas distribution segment earnings increased ~~$0.8~~$3.5 million in the ~~second~~first quarter of ~~2014,~~2015, as compared to the ~~second~~first quarter of ~~2013,~~2014, due primarily to higher firm natural gas sales volumes and peak demand revenues ~~as a result of the addition of new natural gas heating customers.~~

41

Our natural gas distribution segment earnings increased $9.6 million in the first half of 2014, as compared to the first half of 2013, due primarily to higher firm natural gas sales and peak demand revenues as a result ofresulting from colder weather in the first quarter of 2015, as compared to the first quarter of 2014, ~~as well as the addition of new~~and additional natural gas heating ~~customers.~~customers, partially offset by higher property taxes, higher depreciation expense and bad debt expense.

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
June 30, 2014 Compared to 2013

For the Six Months Ended
June 30, 2014 Compared to 2013

Sales (GWh)

Percentage

Sales (GWh)

Percentage
NU – Electric
2014

2013

Decrease

2014

2013

Increase
Residential
4,510

4,720

(4.4)%

10,650

10,523

1.2%
Commercial⁽¹⁾
6,591

6,754

(2.4)%

13,456

13,448

0.1%
Industrial
1,435

1,437

(0.1)%

2,778

2,736

1.5%
Total
12,536

12,911

(2.9)%

26,884

26,707

0.7%

For the Three Months Ended March 31, 2015 Compared to 2014
ES

CL&P

NSTAR Electric

PSNH

WMECO

For the Three Months Ended June 30, 2014 Compared to 2013

For the Six Months Ended June 30, 2014 Compared to 2013

Percentage

Percentage

Percentage

Percentage

CL&P

NSTAR
Electric

PSNH

WMECO

CL&P

NSTAR
Electric

PSNH

WMECO
Sales Volumes (GWh)

Increase/

Increase/

Increase/

Increase/

Percentage
Electric
Percentage
Increase/
(Decrease)

Percentage
Decrease

Percentage
Increase/
(Decrease)

Percentage
Decrease

Percentage
Increase

Percentage
Increase/
(Decrease)

Percentage
Increase

Percentage
Increase/
(Decrease)
2015

2014

(Decrease)

(Decrease)

(Decrease)

(Decrease)

Decrease
Residential
(5.3)%

(4.2)%

(1.8)%

(5.4)%

1.5%

0.2 %

2.4%

0.9 %
6,217

6,139

1.3 %

1.2 %

1.6 %

1.6 %

(0.6)%
Commercial⁽¹⁾
(2.0)%

(3.0)%

(0.6)%

(4.5)%

0.1%

(0.2)%

0.8%

(0.3)%
Commercial
6,930

6,866

0.9 %

0.5 %

1.9 %

(1.0)%

(0.1)%
Industrial
3.4 %

(6.9)%

1.7 %

(3.2)%

3.8%

(1.9)%

3.2%

(2.8)%
1,301

1,343

(3.1)%

(0.9)%

(4.5)%

(4.9)%

(4.7)%
Total
(2.8)%

(3.6)%

(0.6)%

(4.6)%

1.1%

(0.1)%

1.9%

(0.2)%
14,448

14,348

0.7 %

0.8 %

1.4 %

(0.5)%

(1.1)%

⁽¹⁾

~~Commercial retail electric GWh sales include streetlighting and railroad retail sales.~~32

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
June 30, 2014 Compared to 2013

For the Six Months Ended
June 30, 2014 Compared to 2013

Sales (million cubic feet)

Percentage

Sales (million cubic feet)

Percentage
NU – Firm Natural Gas
2014

2013

Increase

2014

2013

Increase
Residential
5,169

4,970

4.0%

24,981

21,985

13.6%
Commercial
6,839

6,622

3.3%

26,467

23,393

13.1%
Industrial
4,916

4,665

5.4%

12,393

11,494

7.8%
Total
16,924

16,257

4.1%

63,841

56,872

12.3%
Total, Net of Special Contracts⁽¹⁾
15,895

15,238

4.3%

61,445

54,660

12.4%

For the Three Months Ended
June 30, 2014 Compared to 2013

For the Six Months Ended
June 30, 2014 Compared to 2013

Sales (million cubic feet)

Sales (million cubic feet)
For the Three Months Ended March 31, 2015 Compared to 2014

Yankee Gas

NSTAR Gas

Yankee Gas

NSTAR Gas
ES

Percentage

Percentage

Percentage

Percentage
Sales Volumes (million cubic feet)

Percentage
Firm Natural Gas
Increase/(Decrease)

Increase

Increase/(Decrease)

Increase
2015

2014

Increase
Residential
(3.4)%

9.6 %

15.8%

12.2%
21,455

19,812

8.3%
Commercial
5.4 %

1.4 %

16.6%

10.2%
21,450

19,627

9.3%
Industrial
5.7 %

4.5%

8.4%

6.4%
7,667

7,478

2.5%
Total
3.3 %

5.0%

13.9%

10.6%
50,572

46,917

7.8%
Total, Net of Special Contracts⁽¹⁾
3.7 %

14.4%

49,381

45,550

8.4%

⁽¹⁾
Special contracts are unique to the customers who take service under such an arrangement and generally specify the amount of distribution revenue to be paid to Yankee Gas regardless of the customers' usage.

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

~~For the second~~Our first quarter of ~~2014, our~~2015 total consolidated retail electric sales ~~consisting of the retail electric sales of CL&P, NSTAR Electric, PSNH, and WMECO,~~volumes were ~~lower,~~higher, as compared to the ~~same period in 2013,~~first quarter of 2014, due primarily to ~~milder temperatures in late May and June, compared with the same periods in 2013. The second~~colder weather. First quarter ~~of 2014 cooling~~2015 heating degree days were 195 percent ~~lower~~higher in Connecticut and western Massachusetts, ~~22 percentlower~~10 percent higher in the Boston metropolitan area, and 244 percent ~~lower~~higher in New Hampshire, as compared to the ~~second~~first quarter of ~~2013.~~2014. Weather-normalized ~~retail~~

42

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

~~For the first half of 2014, our~~Eversource consolidated retail electric sales ~~were higher, as compared to the same period in 2013, due primarily to colder weather~~volumes remained relatively unchanged in the first quarter of ~~2014. The first half 2014 heating degree days were 12 percent higher in Connecticut, New Hampshire and western Massachusetts and 9 percenthigher in the Boston metropolitan area,~~2015, as compared to the first ~~half~~quarter of 2013. Weather-normalized retail electric sales (based on 30-year average temperatures) decreased 0.1 percent in the first half of 2014, as compared to the first half of 2013. We believe the decrease was due primarily to an increase in customer conservation efforts as noted above.2014.

For CL&P (effective December 1, 2014) and WMECO, fluctuations in retail electric sales volumes do not impact earnings due to the ~~DPU-approved~~regulatory commission approved revenue decoupling ~~mechanism. Under this decoupling mechanism,~~mechanisms. Distribution revenues are decoupled from their customer sales volumes. CL&P and WMECO ~~has an overall fixed~~reconcile their annual base distribution rate recovery to pre-established levels of baseline distribution delivery service revenues. Any difference between the allowed level of distribution ~~delivery service revenues of $132.4 million, comprised of customer base rate revenues of $125.4 million~~revenue and the actual amount incurred during a ~~baseline low income discount recovery of $7 million. These two mechanisms~~12-month period is adjusted through rates in the following period. The decoupling mechanism effectively ~~break~~breaks the relationship between sales ~~volume~~volumes and revenues recognized. Prior to December 1, 2014, CL&P recognized LBR related to reductions in sales volume as a result of successful energy efficiency programs. LBR was recovered from retail customers through the FMCC. Effective December 1, 2014, CL&P no longer recognizes LBR due to its revenue decoupling mechanism. NSTAR Electric continues to recognize LBR through December 31, 2015 in accordance with the 2012 DPU-approved comprehensive merger settlement agreement with the Massachusetts Attorney General. For the first quarter of 2015 and 2014, NSTAR Electric recognized LBR of $12.5 million and $8.7 million, respectively.

Our firm natural gas sales are subject to many of the same influences as our retail electric sales. In addition, they have ~~benefitted~~benefited from ~~historically favorable natural gas prices and~~ customer growth across both operating companies. ~~In the second~~Our first quarter ~~and first half of 2014,~~2015 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 ~~second~~first quarter ~~and first half~~ of ~~2013,~~2014, due primarily to colder weather in the first quarter of ~~2014,~~2015, as compared to the first quarter of 2014. The first quarter 2015 weather-normalized Eversource consolidated firm natural gas sales volumes increased 3.2 percent, as compared to the same period in ~~2013,~~2014, due primarily to residential and commercial customer growth in the first half of 2014, as compared to the same period in 2013. The second quarter and first half of 2014 weather-normalized NU consolidated total firm natural gas sales increased 5.3 percent and 4.1 percent, respectively, as compared to the same periods in 2013.growth.

NUES Parent and Other Companies: NUES parent and other companies, which ~~includes~~include our ~~competitive~~unregulated businesses, had net ~~losses~~earnings of ~~$1.9 million and $5.2~~$0.5 million in the ~~second~~first quarter ~~and first half~~ of ~~2014, respectively,~~2015, compared with ~~earnings~~net losses of ~~$1.8 million and $7.3~~$3.2 million in the ~~second~~first quarter ~~and first half~~ of ~~2013, respectively.~~2014. Excluding the impact of integration costs, NUES parent and other companies earned ~~$2.6 million and $5.2~~$4.5 million in the ~~second~~first quarter ~~and first half~~ of ~~2014, respectively,~~2015, compared with ~~$3.6 million and $10.8~~$2.6 million in the ~~second~~first quarter ~~and first half~~ of ~~2013, respectively.~~2014. The ~~decrease~~earnings increase in ~~first half of 2014 earnings~~2015 was due primarily to the absence of ~~the favorable impact from the resolution of the state income tax audit, which provided~~ a ~~$5.8 millionbenefit to first half of 2013 earnings.~~ $2.5 million contribution made in March 2014.

Liquidity

Consolidated: Cash and cash equivalents totaled ~~$34.1~~$71 million as of ~~June 30, 2014,~~March 31, 2015, compared with ~~$43.4~~$38.7 million as of December 31, ~~2013.~~2014.

On April ~~24, 2014, CL&P~~3, 2015, the DPU authorized NSTAR Gas to issue up to $100 million in long-term debt for the period through December 31, 2015.

On January 15, 2015, ES parent issued ~~$250~~$150 million of ~~4.30~~1.60 percent ~~2014~~ Series ~~A First Mortgage Bonds,~~G Senior Notes, due to mature in ~~April 2044.~~2018 and $300 million of 3.15 percent Series H Senior Notes, due to mature in 2025. The proceeds, net of issuance costs, were used to repay short-term ~~borrowings.~~borrowings outstanding under the ES parent commercial paper program.

On April ~~15, 2014, NSTAR Electric~~1, 2015, CL&P repaid at maturity the ~~$300~~$100 million ~~of 4.875~~5.00 percent ~~debentures using short-term debt.~~

~~On July 15, 2014, PSNH repaid at maturity the $50 million of 5.25 percent~~2005 Series LA First and Refunding Mortgage Bonds using short-term ~~debt.~~borrowings. On April 1, 2015, CL&P also redeemed the $62 million 1996A Series 1.55 percent PCRBs that were subject to mandatory tender, using short term borrowings.

~~Effective July 23, 2014, NU~~ES parent, CL&P, PSNH, WMECO, NSTAR Gas and Yankee Gas ~~amended their joint~~are parties to a five-year $1.45 billion revolving credit facility ~~to extend the expiration date an additional year to~~that expires September 6, 2019. The revolving credit facility is ~~to be~~ used primarily to backstop NUES parent's $1.45 billion commercial paper program. The commercial paper program allows NUES parent to issue commercial paper as a form of short-term debt. As of ~~June 30, 2014~~March 31, 2015 and December 31, ~~2013, NU~~2014, ES parent had ~~$710.5~~$788 million and ~~$1.01~~approximately $1.1 billion, respectively, in short-term borrowings outstanding under the NUES parent commercial paper program, leaving ~~$739.5~~$662 million and ~~$435.5~~$348.9 million of available borrowing capacity as of ~~June 30, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, respectively. The weighted-average interest rate on these borrowings as of ~~June 30, 2014~~March 31, 2015 and December 31, ~~2013~~2014 was ~~0.25~~0.53 percent and ~~0.24~~0.43 percent, respectively, which is

33

generally based on A2/P2 rated commercial paper. As of ~~June 30, 2014,~~March 31, 2015, there were intercompany loans from NUES parent of ~~$6.4~~$190.1 million to CL&P, ~~$95~~$82 million to PSNH and ~~$15.9~~$70.5 million to WMECO. As of December 31, ~~2013,~~2014, there were intercompany loans from NUES parent of ~~$287.3~~$133.4 million to CL&P, ~~and $86.5~~$90.5 million to ~~PSNH.~~ PSNH and $21.4 million to WMECO.

~~Effective July 23, 2014,~~ NSTAR Electric ~~amended its~~has a five-year $450 million revolving credit facility ~~to extend the expiration date an additional year to~~that expires September 6, 2019. This facility serves to backstop NSTAR Electric's existing $450 million commercial paper program. As of ~~June 30, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, NSTAR Electric had ~~$194.5~~$215.5 million and ~~$103.5~~$302 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving ~~$255.5~~$234.5 million and ~~$346.5~~$148 million ~~respectively,~~ of available borrowing capacity as of ~~June 30, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, respectively. The weighted-average interest rate on these borrowings as of ~~June 30, 2014~~March 31, 2015 and December 31, ~~2013~~2014 was ~~0.16~~0.35 percent and ~~0.13~~0.27 percent, respectively, which is generally based on A2/P1 rated commercial paper.

Cash flows provided by operating activities totaled ~~$896.7~~$481.8 million in the first ~~half~~quarter of ~~2014,~~2015, compared with ~~$769~~$493.8 million in the first ~~half~~quarter of ~~2013.~~2014. The ~~improved~~decrease in operating cash flows ~~were~~was due primarily to ~~approximately $126 million~~the timing of regulatory recoveries, resulting from both the increase in ~~DOE Phase II Damages proceeds received by~~purchased power and congestion costs at NSTAR Electric, WMECO and CL&P, ~~NSTAR Electric, PSNH and WMECO on June 1, 2014 from the Yankee Companies associated~~along with the ~~spent nuclear fuel litigation,~~timing of collections and payments related to our working capital items, including accounts receivable and accounts payable. Accounts receivable increased due primarily to higher sales volumes in the ~~absence~~first quarter of ~~cash disbursements for major storm restoration costs~~2015 as a result of colder weather, increases in both CL&P’s and NSTAR Electric’s basic service rates effective January 1, 2015, and the ~~decrease~~increase in CL&P's base distribution rates effective December 1, 2014. In addition, there was an increase of ~~$82.2~~approximately $20 million inof Pension and PBOP Plan cash contributions ~~partially offset by an increase in income taxes paid~~ in the first ~~half~~quarter of 2015, compared to the same period in 2014. Partially offsetting these unfavorable cash flow impacts was an income tax refund received in the first quarter of 2015 primarily related to the extension of the accelerated deduction of depreciation in 2014, ~~($158 million),~~which resulted in cash receipts of approximately $250 million in 2015, as compared to income tax payments in the first ~~half~~quarter of 2013 ($16 million). For further information on the spent nuclear fuel litigation, see Note 8C, "Commitments and Contingencies – Contractual Obligations – Yankee Companies," in this combined Quarterly Report on Form 10-Q. 2014.

On April ~~7, 2014, Fitch affirmed~~23, 2015, S&P upgraded the corporate credit ratings by one level and ~~outlook of NU, CL&P, NSTAR Electric, PSNH, WMECO and NSTAR Gas. On April 25, 2014, S&P affirmed the corporate credit ratings and revised the~~ outlooks to stable from positive ~~from stable~~ of ~~NU,~~ES parent, CL&P, NSTAR Electric, PSNH, WMECO, Yankee Gas and NSTAR Gas.

43 A summary of our corporate credit ratings and outlooks by Moody's, S&P and Fitch is as follows:

Moody's
S&P
Fitch
Current
Outlook
Current
Outlook
Current
Outlook
ES Parent
Baa1
Stable
A
Stable
BBB+
Stable
CL&P
Baa1
Stable
A
Stable
BBB+
Stable
NSTAR Electric
A2
Stable
A
Stable
A
Stable
PSNH
Baa1
Stable
A
Stable
BBB+
Stable
WMECO
A3
Stable
A
Stable
BBB+
Stable

In the first ~~half~~quarter of ~~2014,~~2015, we had cash dividends on common shares of ~~$237.2~~$132.5 million, compared with ~~$232~~$118.5 million in the first ~~half~~quarter of ~~2013.~~2014. On ~~May 1, 2014,~~February 3, 2015, our Board of Trustees approved a common share dividend payment of ~~$0.3925~~$0.4175 per share, ~~which was~~payable on March 31, 2015 to shareholders of record as of March 2, 2015. The dividend represented an increase of 6.4 percent over the dividend paid in December 2014. On April 29, 2015, our Board of Trustees approved a common share dividend payment of $0.4175 per share, payable on June 30, ~~2014~~2015 to shareholders of record as of May ~~30, 2014.~~29, 2015.

In the first ~~half~~quarter of ~~2014,~~2015, CL&P, NSTAR Electric, PSNH, and WMECO paid ~~$85.6~~$49 million, ~~$253~~$49.5 million, ~~$33~~$26.5 million, and ~~$49~~$9.3 million, respectively, in common stock dividends to NUES parent.

Investments in Property, Plant and Equipment on the ~~accompanying~~ statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension expense. In the first ~~half~~quarter of ~~2014,~~2015, investments for ~~NU,~~Eversource, CL&P, NSTAR Electric, PSNH, and WMECO were ~~$724~~$362.6 million, ~~$221.4~~$127.6 million, ~~$213.5~~$79.8 million, ~~$117.4~~$71.9 million, and ~~$61.5~~$35.9 million, respectively.

Business Development and Capital Expenditures

~~Consolidated:~~ Our consolidated capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized portions of pension expense (all of which are non-cash factors), totaled ~~$706.2~~$310.5 million in the first ~~half~~quarter of ~~2014,~~2015, compared with ~~$644~~$277.9 million in the first ~~half~~quarter of ~~2013.~~2014. These amounts included ~~$25.5~~$8.4 million and ~~$6.7~~$5.9 million in the first ~~half~~quarter of ~~2014~~2015 and ~~2013,~~2014, respectively, related to ~~our corporate service~~information technology and facilities upgrades and enhancements, primarily at Eversource Service and The Rocky River Realty Company.

Access Northeast: In September 2014, Eversource 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. Eversource and Spectra Energy Corp will have equal ownership interest in the project with the option of additional investors in the future. On February 18, 2015, National Grid was added as a co-developer in the project for a total ownership interest of 20 percent, with Eversource and Spectra Energy Corp each owning 40 percent. 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.

In December 2014, Eversource and Spectra Energy Corp announced an alliance with Iroquois Gas Transmission for the Access Northeast project. This alliance will provide New England natural gas distribution companies ~~NUSCO~~ and ~~RRR.~~generators with additional access to natural gas supplies from multiple, diverse receipt points along the Algonquin pipeline system, including the Iroquois pipeline system.

34

Transmission Business: Overall, transmission business capital expenditures increased by ~~$9.6~~$37.9 million in the first ~~half~~quarter of ~~2014,~~2015, as compared to the first ~~half~~quarter of ~~2013.~~2014. A summary of transmission capital expenditures by company ~~for the first half of 2014 and 2013~~ is as follows:

For the Six Months Ended June 30,

For the Three Months Ended March 31,
(Millions of Dollars)

2014

2013

2015

2014
CL&P

$
111.6

$
84.1

$
42.4

$
36.2
NSTAR Electric

70.2

79.3

21.4

12.4
PSNH

44.3

35.0

28.9

16.7
WMECO

33.1

41.5

23.8

16.3
NPT

12.4

22.1

9.7

6.7
Total Transmission Segment

$
271.6

$
262.0

$
126.2

$
88.3

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

The Interstate Reliability Project ~~which~~(IRP) includes CL&P's construction of an approximately 40-mile, ~~345 kV~~345-kV overhead line from Lebanon, Connecticut to the Connecticut-Rhode Island border in Thompson, Connecticut where it will connect to transmission enhancements being constructed by National Grid in Rhode Island and Massachusetts, is the second major NEEWS project. As of May 2014, all three states have issued siting approvals. Completing all the project permit requirements, the Army Corps of Engineers issued its permit on the project in the first quarter of 2014. Project construction isMassachusetts. Construction has been underway in all three ~~states. NU's~~states since March 2014. Eversource's portion of the cost is estimated to be $218 million, and ~~construction on its portion of the project is approximately 40 percent~~we expect to complete ~~as of June 30, 2014. The project is expected to be placed in service~~IRP by the end of 2015. As of March 31, 2015, IRP was approximately 90 percent complete, and CL&P had placed $34 million in service.

The Greater Hartford Central Connecticut ~~Study~~ (GHCC), which includes the reassessment of the Central Connecticut Reliability Project, continues to make progress. The final need results showed existing and worsening severe regional and local thermal overloads and voltage violations within each of the areas studied and across the interfaces of those areas. These results were presented to the ISO-NE Planning Advisory Committee in November 2013. On July 15, 2014, ISO-NE presented the preferred transmission solutions to its Planning Advisory Committee. These solutions are comprised of many ~~115 kV~~115-kV upgrades and are expected to cost approximately $350 million and be placed in service from 2016 through 2018. ISO New England posted the final Solutions Study for GHCC in late ~~2017.~~

~~Included as part~~February 2015. The Reliability Committee recommended approval of ~~NEEWS~~our Proposed Plan Applications to ISO New England at its March 17, 2015 meeting. The first siting filing for these projects was made to the Connecticut Siting Council on February 27, 2015. Additional siting filings are ~~associated reliability related~~expected to be made throughout 2015 and 2016. We expect to begin work on these projects ~~$93.1 million of which have been placed~~ in ~~service. As of June 30, 2014, all construction on the associated reliability related projects has been completed.~~ mid-2015 and complete GHCC-related work in 2018.

Through ~~June 30, 2014,~~March 31, 2015, CL&P and WMECO capitalized ~~$292~~$371.4 million and ~~$573.4~~$573.7 million, respectively, in costs associated with NEEWS. Included in the NEEWS amounts are costs for IRP, of which ~~$39.2~~CL&P capitalized $183.8 million in costs through March 31, 2015, and ~~$6.4~~$15 million ~~respectively, were capitalized~~ in the first ~~half~~quarter of ~~2014.~~ 2015.

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

44The $1.4 billion project is subject to federal and state public permitting processes and is now expected to be operational in the first half of 2019.

Greater Boston Reliability ~~and Boston Network Improvements:~~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~~projects over the next five ~~years.~~years to enhance the region's system reliability. On February 12, 2015, ISO-NE selected Eversource's and National Grid's proposed Greater Boston and New Hampshire Solution (Solution) as its preferred option because it is significantly less expensive than an alternate proposal and has superior performance criteria. The Solution consists of important electric transmission upgrades encompassing the Merrimack Valley area of southern New Hampshire and the metropolitan Boston area. We ~~expect ISO-NE to select preferred solutions~~estimate our investment in the ~~second half of 2014,~~Solution will be $489 million, and ~~project costs to be approximately $495 million for these new initiatives.~~we are pursuing the necessary regulatory approvals.

35

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

For the Six Months Ended June 30,
For the Three Months Ended March 31,
(Millions of Dollars)
2014

2013
2015

2014
CL&P:

Basic Business
$
24.3

$
27.8
$
27.2

$
10.7
Aging Infrastructure

74.7

71.3

34.2

34.3
Load Growth

34.7

31.8

11.5

17.3
Total CL&P

133.7

130.9

72.9

62.3
NSTAR Electric:

Basic Business

50.2

48.3

22.2

29.6
Aging Infrastructure

53.1

51.3

13.5

22.9
Load Growth

14.7

13.4

3.9

6.5
Total NSTAR Electric

118.0

113.0

39.6

59.0
PSNH:

Basic Business

14.1

8.5

12.3

5.8
Aging Infrastructure

26.5

20.0

9.2

12.5
Load Growth

13.1

10.1

6.7

6.1
Total PSNH

53.7

38.6

28.2

24.4
WMECO:

Basic Business

4.5

3.7

3.1

1.5
Aging Infrastructure

8.1

10.8

4.5

3.3
Load Growth

2.8

3.3

1.8

1.4
Total WMECO

15.4

17.8

9.4

6.2
Total - Electric Distribution (excluding Generation)

320.8

300.3

150.1

151.9
PSNH Generation

5.2

4.3

2.6

2.5
WMECO Generation

7.4

0.3

-

4.1
Total - Natural Gas

75.7

70.3

23.2

25.2
Total Electric and Natural Gas Distribution Segment
$
409.1

$
375.2
Total Distribution Segment
$
175.9

$
183.7

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~~plant 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.

NSTAR Electric's capital spending program decreased by $19.4 million in the first quarter of 2015, as compared to the first quarter of 2014, as a result of the impact from the winter weather and storms in the greater Boston metropolitan area.

Natural Gas Business Expansion and Enhancement: In 2013, in accordance with Connecticut law and regulations, PURA approved a comprehensive joint natural gas infrastructure expansion plan (expansion plan) filed by Yankee Gas and other Connecticut natural gas distribution companies. The expansion plan described how Yankee Gas expects to add approximately 82,000 new natural gas heating customers over a 10-year period. Yankee Gas estimates that its portion of the plan will cost approximately $700 million over 10 years. In January 2015, PURA approved a joint settlement agreement proposed by Yankee Gas and other Connecticut natural gas distribution companies and regulatory agencies that clarified the procedures and oversight criteria applicable to the expansion plan.

In October 2014, pursuant to new legislation, NSTAR Gas filed the Gas System Enhancement Program (GSEP) with the DPU. NSTAR Gas' program accelerates the replacement of certain natural gas distribution facilities 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. On April 30, 2015, the DPU approved the GSEP. We have projected capital expenditures of approximately $200 million for the period 2015 through 2018 for the GSEP, which are consistent with our request in the NSTAR Gas rate case application currently before the DPU.

FERC Regulatory Issues

FERC ~~Base~~ ROE Complaints: ~~On September 30,~~Beginning in 2011, ~~a complaint was~~three separate complaints were filed ~~jointly~~ at FERC ~~under Sections 206 and 306~~by combinations of ~~the Federal Power Act by several~~ New England state attorneys general, state regulatory commissions, consumer advocates, consumer groups, municipal parties and other parties (the "Complainants"). ~~The~~In these three separate complaints, the Complainants ~~alleged that~~challenged the NETOs' base ROE of 11.14 percent that ~~has been~~was 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 it prospectively from the date of the final FERC order and for the 15-month complaint refund periods stipulated in the separate complaints. In 2014, the FERC ordered the base ROE ~~effective October 1, 2011, and~~ to ~~require refunds. The FERC~~be set ~~the case for trial before a FERC ALJ after settlement negotiations were unsuccessful in August 2012.~~

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

~~On June 19, 2014, FERC issued an order partially affirming and partially reversing the ALJ's initial decision. FERC set a single tentative base ROE of~~ 10.57 percent for the 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~~prospectively from October 16, 2014 and ~~oil pipeline projects. Using this methodology, FERC determined a new zone of reasonableness of 7.03 percent to 11.74 percent, and set the tentative base ROE at the 75~~^th ~~percentile of this new zone. FERC also stated~~ that a utility's total or maximum ROE ~~inclusive of transmission incentive ROE adders, should~~shall not exceed the top of the new zone of reasonableness, ~~produced~~which was set at 11.74 percent. The NETOs and the Complainants sought rehearing from FERC. In late 2014, the NETOs made a compliance filing, which was challenged by ~~this methodology.~~the Complainants, and in accordance with FERC ~~instituted a paper hearing~~orders, began issuing refunds to customers from the first complaint period.

On March 3, 2015, FERC issued an order denying all issues raised on ~~the long-term growth rate portion of the methodology, before it issues a final determination on the base ROE. On July 21, 2014,~~rehearing by the NETOs and Complainants ~~filed rehearing requests~~ in ~~this proceeding.~~

the first base ROE complaint. The FERC order upheld the base ROE of 10.57 percent for the first complaint refund period and prospectively from October 16, 2014, and upheld that the utility's total ROE (the base ROEplus anyincentive adders) for the transmission assets to which the adder applies is capped at the top of the zone of reasonableness, which is currently set at 11.74 percent. As a result ofclarifying information related to how the ROE cap is applied, which is contained in the order, Eversource adjusted its reservein the first quarter of 2015 and recognized an after-tax charge to earnings (excluding interest)

4536

~~On December 27, 2012, a second complaint~~of $12.4 million, of which $7.9 million was filed jointly at FERC by several additional consumer groups and municipal parties, which challenged the NETOs' base ROE and sought refunds for the 15-month period beginning January 1, 2013. On June 19, 2014, the FERC issued a second order finding that the complaint raised issues of material fact, and set this complaint for trial, should settlement negotiations be unsuccessful. FERC stated that it could issue an order in this case by mid-2016. On July 21, 2014, the NETOs filed a rehearing request in this proceeding.

~~Though NU cannot predict the ultimate outcome of this proceeding, in the second quarter of 2014, the Company~~ recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact from the FERC's two orders issued on June 19, 2014 for the two refund periods. The aggregate after-tax charge to second quarter 2014 earnings totaled $32.1 million at NU, which represented reserves of $18.5 million at CL&P, ~~$6.1~~$1.4 million at NSTAR Electric, $2$0.6 million at PSNH, and ~~$5.5~~$2.5 million at WMECO. The charge was recorded as a regulatory liability.

FERC Order No. 1000: On ~~July 31, 2014,~~March 19, 2015, FERC acted on all rehearing requests filed by the ~~Complainants filed an~~NETOs, including CL&P, NSTAR Electric, PSNH and WMECO, and other parties and accepted the November 2013 compliance filing made by ISO-NE and the NETOs, subject to further compliance. FERC accepted our proposal that the new competitive transmission planning process will not apply to certain projects, which have been declared as the preferred solution by ISO-NE, unless ISO-NE later decides the solution must be re-evaluated. FERC determined on rehearing that we can restore provisions that recognize the NETOs’ rights to retain use and control of their existing rights of ways (ROWs).

FERC affirmed that it can eliminate our right of first refusal to build transmission in New England even though FERC previously approved and granted special protections to these rights. We are currently evaluating this and other parts of the FERC decision with the NETOs and ISO-NE. Implementation of FERC's goals in New England, including within our service territories, may expose us to competition for construction of transmission projects, additional ~~complaint~~regulatory considerations, and potential delay with ~~FERC. At this time,~~respect to future transmission projects. While the ~~Company cannot determine the outcome~~FERC Orders may bring new challenges, we believe there are also opportunities for us to compete for transmission reliability projects outside of ~~this complaint.~~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 ~~half~~quarter of ~~2014,~~2015, 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~~Eversource 2014 Annual Report on Form 10-K.

Connecticut:

~~Distribution Rates~~Yankee Gas - Settlement Agreement: On ~~June 9, 2014, CL&P filed~~April 29, 2015, the PURA approved a settlement agreement entered into among Yankee Gas, the Connecticut Office of Consumer Counsel, and the PURA Staff, which eliminates the requirement to file a rate case in 2015. Under the terms of the settlement agreement, Yankee Gas will provide a $1.5 million rate credit to firm customers beginning in December 2015, will establish an ~~application~~earnings sharing mechanism whereby Yankee Gas and its customers will share equally any earnings exceeding a 9.5 percent ROE in a twelve month period commencing with the ~~PURA~~period from April 1, 2015 through March 31, 2016, and Yankee Gas shall forgo its right to ~~amend customer rates, effective December 1, 2014. CL&P requested~~file a rate case for an increase in ~~total~~its base distribution rates prior to January 1, 2017. This does not impact the rates charged under the CES program. In addition, the settlement agreement resolves two pending regulatory proceedings before PURA pertaining to a review of ~~$231.5 million.~~Yankee Gas’ overearnings. In the first quarter of 2015, Yankee Gas recorded the $1.5 million expected refund to customers as a reduction to operating revenues.

Massachusetts:

2014 Comprehensive Settlement Agreement: On March 2, 2015, the DPU approved the comprehensive settlement agreement between NSTAR Electric, NSTAR Gas and the Massachusetts Attorney General (the "Settlement") as filed with the DPU on December 31, 2014. The Settlement resolved the outstanding NSTAR Electric CPSL program filings for 2006 through 2011, the NSTAR Electric and NSTAR Gas PAM and energy efficiency-related customer billing adjustments reported in 2012, and the recovery of LBR related to NSTAR Electric's energy efficiency programs for 2008 through 2011 (11 dockets in total). As a result, NSTAR Electric and NSTAR Gas will refund a combined $44.7 million to customers. The refund was recorded as a regulatory liability as of March 31, 2015 and NSTAR Electric recognized a $13 million after-tax benefit in the first quarter of 2015.

Basic Service Bad Debt Adder: In accordance with a generic 2005 DPU order, electric utilities in Massachusetts recover the energy-related portion of bad debt costs in their Basic Service rates. In February 2007, NSTAR Electric filed its 2005 through 2006 Basic Service reconciliation with the DPU proposing an adjustment related to the increase ~~includes a~~of its Basic Service bad debt charge-offs. In June 2007, the DPU approved NSTAR Electric's proposed adjustment to the Basic Service Adder but instructed NSTAR Electric to reduce distribution rates by an equal and offsetting amount. This adjustment to NSTAR Electric's distribution rates would have eliminated 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. NSTAR Electric took the position that it had fully removed the collection of energy-related bad debt costs from its base distribution ~~rate increase of $116.7 million, an increase~~rates effective January 1, 2006; therefore, no further adjustment to distribution rates was warranted. In 2012, the SJC vacated the DPU order and remanded the matter to the DPU for the annual recovery of $89.5 million of previously approved 2011 and 2012 deferred storm restoration costs totaling $365 million, and an increase of $25.3 million for previously approved electric system resiliency costs. Currently, hearings are scheduled to occur in late August through September, and a final decision is expected in December 2014.further review.

On ~~June 17, 2014, PURA~~January 7, 2015, the DPU issued an order concluding that NSTAR Electric had appropriately accounted for the removal of supply-related bad debt costs from base distribution rates effective January 1, 2006. The DPU ordered ~~CL&P~~NSTAR Electric and the Massachusetts Attorney General to use the DOE Phase II Damages proceeds of $65.4 million received on June 1, 2014 to offset the $365 million in 2011 and 2012 deferred storm restoration costs that were approved for recovery by the PURA on March 12, 2014. For further informationcollaborate on the ~~spent nuclear fuel litigation awards, see Note 8C, "Commitments and Contingencies – Contractual Obligations – Yankee Companies." As~~reconciliation of energy-related bad debt costs through 2014. During the second quarter of 2015, NSTAR Electric expects to file with the DPU to recover from customers approximately $43 million of supply-related bad debt costs. In the first quarter of 2015, as a result ~~CL&P will now recover approximately $300 million in storm costs from customers, which will be reflected in final rates approved by PURA at the conclusion~~ of the ~~current CL&P distribution rate case.~~DPU order, NSTAR Electric increased its regulatory assets by $24.2 million, resulting in an increase in after-tax earnings of $14.5 million.

New Hampshire:

PSNH Generation Agreement::~~In 2013, the NHPUC opened~~ On March 11, 2015, PSNH entered into an agreement in principle in 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~~settlement Term Sheet with the New Hampshire ~~competitive electric market. In a 2013 NHPUC staff report accepted by~~Office of Energy and Planning, certain members of the Staff of the NHPUC, the NHPUC staff recommended that the NHPUC examine whether default service rates remain sustainable on a going forward basis, define "just and reasonable" with respect to default service in the context of competitive retail markets, analyze the current and expected value of PSNH's generating units, and identify means to mitigate and address stranded cost recovery. In October 2013, the New Hampshire Legislative Oversight Committee on Electric Utility Restructuring (Oversight Committee) requested that the NHPUC conduct an analysis to determine whether it is now in the economic interest of PSNH's retail customers for PSNH to divest its interest in generation plants. On November 1, 2013, the Oversight Committee asked for a preliminary report by April 1, 2014 that would include a third party valuation of PSNH's generating assets and a report from NHPUC staff members concerning customers' economic interests in those generating assets.

On April 1, 2014, the NHPUC staff issued a "Preliminary Status Report Addressing the Economic Interest of PSNH's Retail Customers as it Relates to the Potential Divestiture of PSNH's Generating Plants," which included a consultant's analysisOffice of the ~~fair market value~~Consumer Advocate, and two State Senators. The Term Sheet is designed to provide a resolution of ~~PSNH generating assets and long-term power purchase contracts. The consultant's analysis estimated the fair market value of~~issues pertaining to PSNH's generation assets ~~to be $225 million as~~in pending regulatory proceedings before the NHPUC. Under the terms 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 inthe Term Sheet, the Clean Air Project ~~(scrubber)~~ prudence ~~proceeding; (2) that existing laws regarding divestiture, energy service,~~proceeding will be resolved and ~~cost recovery~~all remaining Clean Air Project costs will 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,~~included in response to the NHPUC staff report, the House and Senate passed a bill, which enacted changes to the laws governing divestiture of PSNH's generating assets. That bill requires the NHPUC to initiate a proceeding beforerates effective January 1, ~~2015,~~2016. PSNH has agreed to determine whether all or some of PSNH's generation assets should be divested. A progress report from the NHPUC must be made by March 31, 2015. The bill also changes the law to give the NHPUC express authority to orderpursue the divestiture of ~~all or some of PSNH's~~its generation assets ~~if the~~upon NHPUC finds it is in the economic interest of customers to do so. The bill also clarifies the definition of "stranded costs" to include costs approved for recovery by the NHPUC in connection with the divestiture or retirement of PSNH's generation assets.

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

4637

~~Legislative~~approval of a final Settlement Agreement reflecting the provisions of the Term Sheet. As part of the planned Settlement Agreement, PSNH has agreed to forego recovery of $25 million of the deferred equity return related to the Clean Air Project. Upon completion of the divestiture process, all remaining stranded costs, including any remaining deferred equity return in excess of the $25 million that PSNH has agreed to forego, will be recovered via bonds that will be secured by a non-bypassable charge to PSNH's customers. In addition, PSNH will not seek a general distribution rate increase that would become effective before July 1, 2017 and ~~Policy Matters~~will contribute $5 million to create a clean energy fund, which will not be recoverable from its customers.

~~Massachusetts:~~

~~Gas Replacement~~Consummation of the Term Sheet provisions is conditioned upon the enactment of authorizing securitization legislation in New Hampshire, completion of the Settlement Agreement, and ~~Expansion~~:NHPUC approval of the Settlement Agreement. On ~~July 7, 2014, Massachusetts enacted "An Act Relative~~March 26, 2015, the New Hampshire Senate passed the legislation, which is currently pending in the New Hampshire House. We expect legislation to ~~Natural Gas Leaks" (the Act). The Act establishes a uniform natural gas leak classification standard for all Massachusetts natural gas utilities~~be finalized in the third quarter of 2015 and a ~~program that accelerates the replacement of aging natural gas infrastructure. The program will enable companies, including NSTAR Gas,~~NHPUC decision 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. be issued in late 2015.

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~~Eversource 2014 Form 10-K. There have been no material changes with regard to these critical accounting policies.

Other Matters

Accounting ~~Standards Recently Adopted:~~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 8B, "Commitments~~There have been no material contractual obligations identified and ~~Contingencies – Long-Term Contractual Arrangements," for discussion of~~no material changes with regard to the contractual ~~obligations.~~obligations and commercial commitments previously disclosed in the Eversource 2014 Form 10-K.

Web Site: Additional financial information is available through our ~~web~~website atwww.eversource.com. We make available through our website a link to the SEC's EDGAR website (http://www.sec.gov/edgar/searchedgar/companysearch.html), at which site at~~www.nu.com~~.Eversource's, CL&P's, NSTAR Electric's, PSNH's and WMECO's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports may be reviewed. 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.

4738

RESULTS OF OPERATIONS – ~~NORTHEAST UTILITIES~~EVERSOURCE ENERGY AND SUBSIDIARIES

The following provides the amounts and variances in operating revenues and expense line items ~~for~~in the ~~condensed consolidated~~ statements of income for NUEversource for the three months ended March 31, 2015 and 2014 included in this Quarterly Report on Form ~~10-Q for the three and six months ended June 30, 2014 and 2013:~~10-Q:

Operating Revenues and Expenses

Operating Revenues and Expenses

For the Three Months Ended June 30,

For the Six Months Ended June 30,

Increase/

Increase/

(Millions of Dollars)
2014

2013

(Decrease)

Percent

2014

2013

(Decrease)

Percent

Operating Revenues
$
1,677.6

$
1,635.9

$
41.7

2.5
%

$
3,968.2

$
3,630.9

$
337.3

9.3
%
Operating Expenses:

Purchased Power, Fuel and Transmission

624.2

488.3

135.9

27.8

1,602.4

1,236.1

366.3

29.6

Operations and Maintenance

373.2

357.2

16.0

4.5

724.9

703.3

21.6

3.1

Depreciation

152.2

159.5

(7.3)

(4.6)

303.0

314.5

(11.5)

(3.7)

Amortization of Regulatory
Assets/(Liabilities), Net

(3.5)

54.6

(58.1)

(a)

54.4

108.6

(54.2)

(49.9)

Amortization of Rate Reduction Bonds

-

8.1

(8.1)

(100.0)

-

42.6

(42.6)

(100.0)

Energy Efficiency Programs

102.7

94.1

8.6

9.1

241.5

199.9

41.6

20.8

Taxes Other Than Income Taxes

134.8

123.5

11.3

9.1

280.3

256.4

23.9

9.3

Total Operating Expenses

1,383.6

1,285.3

98.3

7.6

3,206.5

2,861.4

345.1

12.1

Operating Income
$
294.0

$
350.6

$
(56.6)

(16.1)
%

$
761.7

$
769.5

$
(7.8)

(1.0)
%

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

Operating Revenues

For the Three Months Ended June 30,

For the Six Months Ended June 30,

(Millions of Dollars)
2014

2013

Increase/
(Decrease)

Percent

2014

2013

Increase/
(Decrease)

Percent

Electric Distribution
$
1,261.8

$
1,221.6

$
40.2

3.3
%

$
2,847.8

$
2,595.8

$
252.0

9.7
%
Natural Gas Distribution

195.5

154.1

41.4

26.9

628.3

515.9

112.4

21.8

Total Distribution

1,457.3

1,375.7

81.6

5.9

3,476.1

3,111.7

364.4

11.7

Transmission

206.9

247.9

(41.0)

(16.5)

458.9

487.4

(28.5)

(5.8)

Total Regulated Companies

1,664.2

1,623.6

40.6

2.5

3,935.0

3,599.1

335.9

9.3

Other and Eliminations

13.4

12.3

1.1

8.9

33.2

31.8

1.4

4.4

Total Operating Revenues
$
1,677.6

$
1,635.9

$
41.7

2.5
%

$
3,968.2

$
3,630.9

$
337.3

9.3
%

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

For the Three Months Ended June 30,

For the Six Months Ended June 30,

Increase/

2014

2013

(Decrease)

Percent

2014

2013

Increase

Percent

Retail Electric Sales in GWh
12,536

12,911

(375)

(2.9)
%

26,884

26,707

177

0.7
%
Firm Natural Gas Sales in Million Cubic Feet
16,924

16,257

667

4.1

63,841

56,872

6,969

12.3

Operating Revenues and Expenses

For the Three Months Ended March 31,

Increase/

(Millions of Dollars)
2015

2014

(Decrease)

Percent

Operating Revenues
$
2,513.4

$
2,290.6

$
222.8

9.7
%

Operating Expenses:

Purchased Power, Fuel and Transmission

1,162.1

978.2

183.9

18.8

Operations and Maintenance

333.4

351.7

(18.3)

(5.2)

Depreciation

163.8

150.8

13.0

8.6

Amortization of Regulatory Assets, Net

60.6

57.9

2.7

4.7

Energy Efficiency Programs

146.6

138.8

7.8

5.6

Taxes Other Than Income Taxes

149.4

145.5

3.9

2.7

Total Operating Expenses

2,015.9

1,822.9

193.0

10.6

Operating Income

497.5

467.7

29.8

6.4

Interest Expense

94.8

90.0

4.8

5.3

Other Income, Net

5.7

1.7

4.0

(a)

Income Before Income Tax Expense

408.4

379.4

29.0

7.6

Income Tax Expense

153.2

141.5

11.7

8.3

Net Income

255.2

237.9

17.3

7.3

Net Income Attributable to Noncontrolling Interests

1.9

1.9

-

-

Net Income Attributable to Controlling Interest
$
253.3

$
236.0

$
17.3

7.3
%

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

Operating Revenues

For the Three Months Ended March 31,

Increase/

(Millions of Dollars)
2015

2014

(Decrease)

Percent

Electric Distribution
$
1,760.1

$
1,585.9

$
174.2

11.0
%

Natural Gas Distribution

507.4

432.8

74.6

17.2

Total Distribution

2,267.5

2,018.7

248.8

12.3

Transmission

249.0

252.1

(3.1)

(1.2)

Total Regulated Companies

2,516.5

2,270.8

245.7

10.8

Other and Eliminations

(3.1)

19.8

(22.9)

(a)

Total Operating Revenues
$
2,513.4

$
2,290.6

$
222.8

9.7
%

(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 March 31,

2015

2014

Increase

Percent

Retail Electric Sales Volumes in GWh

14,448

14,348

100

0.7
%

Firm Natural Gas Sales Volumes in Million Cubic Feet

50,572

46,917

3,655

7.8

Operating Revenues increased by $222.8 million in the ~~second~~first quarter of ~~2014,~~2015, as compared to the ~~second~~same period in 2014.

Electric distribution segment revenues increased by $174.2 million as a result of the impact of both weather and increased rates on our base distribution revenues ($35 million), the 2014 Comprehensive Settlement Agreement at NSTAR Electric ($11 million), and the aggregate impact on revenues of corresponding costs that are recovered through our cost tracking mechanisms, which were the result of increases in energy supply costs ($211 million), offset by decreased costs associated with federally mandated congestion charges and transition costs ($46.6 million).

Energy supply costs were impacted by the overall New England wholesale energy supply market in which natural gas delivery costs are adversely impacting the cost of electric energy purchased for our retail electric customers. Energy supply costs are recovered from customers in rates through cost tracking mechanisms and therefore have no impact on earnings. Electric distribution segment revenues were favorably impacted by an increase in base distribution revenues, which reflected a 0.7 percent increase in retail electric sales volumes driven primarily by the colder winter weather experienced throughout our service territories in the first quarter of ~~2013.~~ 2015, and the impact of CL&P's base distribution rate case effective December 1, 2014. Additionally, in connection with the 2014 Comprehensive Settlement Agreement, NSTAR Electric recognized an $11 million benefit to distribution revenues in the first quarter of 2015. These increases were partially offset by decreases in rates related to the recovery of costs associated with federally mandated congestion charges and transition cost recovery revenues, which are also recovered through cost tracking mechanisms.

Effective December 1, 2014, CL&P’s distribution revenues were decoupled from its sales volumes and CL&P no longer recognized LBR. This is similar to WMECO's revenue decoupling mechanism in that it provides CL&P a base amount of distribution revenues ($1.041 billion on an annual basis) and effectively breaks the relationship between revenues and customer electricity usage. Revenue decoupling mechanisms ensure the recovery of our approved base distribution revenue requirements. Therefore, changes in sales volumes have no impact on the level of base distribution revenue realized. In the first quarter of 2014, which was colder than normal, CL&P’s rates were not decoupled.

39

The natural gas distribution segment revenues increased by $74.6 million due primarily to an increase in rates related to the recovery of costs associated with the procurement of natural gas supply ($56.1 million). Natural gas supply costs were impacted by the overall New England wholesale energy supply market in which natural gas delivery costs are adversely impacting the cost of natural gas purchased on behalf of our retail natural gas customers. Natural gas supply costs are recovered from customers in rates through cost tracking mechanisms and therefore have no impact on earnings. In addition, revenues increased due to the firm natural gas base distribution revenues increase ($12.4 million) due primarily ~~reflects~~to a 7.8 percent increase in firm natural gas sales volumes, which was driven primarily by the colder winter. The weather conditions experienced were significantly colder than both normal and the same period last year throughout our natural gas service territories in Connecticut and Massachusetts. Weather-normalized firm natural gas sales volumes (based on 30-year average temperatures) increased 3.2 percent in 2015, as compared to 2014, due primarily to residential and commercial customer growth.

The transmission segment revenues decreased by $3.1 million due primarily to the impact of the $20 million reserve related to the March 2015 FERC ROE order, partially offset by the recovery of higher revenue requirements associated with ongoing investments in our transmission infrastructure.

Purchased Power, Fuel and Transmission expense includes costs associated with purchasing electricity and natural gas on behalf of our customers. ~~Fluctuations in these~~These energy supply costs are recovered from customers in rates ~~and therefore~~through cost tracking mechanisms, which have no impact on ~~earnings. Retail electric sales volumes decreased 2.9 percent from the second quarter of 2013 as a result of milder temperatures in late May~~earnings (tracked costs). Purchased Power, Fuel and ~~June of 2014, as well as the impact of utility-sponsored energy efficiency programs. Firm natural gas sales volume~~Transmission increased ~~4.1 percent from the second quarter of 2013 as customer growth and economic conditions in our service territory have shown steady improvement over the past year.~~

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

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

Operating Revenues increased in the first half of 2014, as compared to the first half of 2013. The increase reflects higher retail electric and firm natural gas sales volumes primarily as a result of the significantly colder weather in the first quarter of ~~2014,~~2015, as compared to the same period in ~~2013,~~2014, due primarily to the following:

(Millions of Dollars)
Increase/(Decrease)
Electric Distribution
$
138.6
Natural Gas Distribution
62.3
Transmission
0.9
Other and Eliminations
(17.9)
Total Purchased Power, Fuel and Transmission
$
183.9

The increase in purchased power at the electric and natural gas distribution businesses were driven by the ~~overall impact of~~ higher costs associated with the procurement of energy supply. Our energy supply costs were impacted by higher natural gas ~~transportation~~delivery costs which, in addition to its impact on the cost of natural gas purchased on behalf of our retail natural gas customers, had an adverse impact on the cost of ~~purchased~~ electric energy purchased for our retail electric customers. ~~Fluctuations in energy supply costs are recovered from customers in rates and therefore have no impact on earnings.~~

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

48

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

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

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

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

Three Months Ended

Six Months Ended
(Millions of Dollars)
Increase/(Decrease)

Increase/(Decrease)
Electric distribution segment fuel and energy supply costs
$
139.6

$
334.7
Firm natural gas sales related costs

35.3

69.2
Transmission segment costs

(0.7)

(3.2)
All other (including eliminations)

3.6

15.7
Partially offset by:

Electric distribution segment purchased power and deferred fuel costs

(41.9)

(50.1)

$
135.9

$
366.3

Operations and Maintenanceexpense includes tracked costs ~~that are recovered in rates through cost tracking mechanisms, which have no earnings impact (tracked costs),~~ and costs that are recovered through base electric and natural gas distribution ~~rates (and~~rates; therefore variances impact ~~earnings)~~earnings (non-tracked costs). Operations and Maintenance ~~increased for~~decreased in the ~~three and six months ended June 30, 2014,~~first quarter of 2015, as compared to the same ~~periods~~period in ~~2013,~~2014, due primarily to the following:

Three Months Ended

Six Months Ended
(Millions of Dollars)
Increase/(Decrease)

Increase/(Decrease)
Base Electric Distribution:

   Bad debt expense
$
2.0

$
5.2
   Implementation of a new outage restoration program at CL&P

3.7

3.8
   Employee costs, including pension and benefit related costs

(20.2)

(30.9)
   Storm costs

0.4

(4.8)
   Other operations and maintenance

7.2

9.1
Total Base Electric Distribution

(6.9)

(17.6)
Total Natural Gas Distribution

(1.1)

3.0
Total Tracked costs (Transmission and Electric Distribution)

14.4

23.5
Total Distribution and Transmission

6.4

8.9
Other and eliminations:

  Integration and severance costs

4.7

11.5
  All other (including eliminations)

4.9

1.2
Total Operations and Maintenance
$
16.0

$
21.6
(Millions of Dollars)
Increase/(Decrease)
Base Electric Distribution:
   Resolution of basic service bad debt adder mechanism at NSTAR Electric
$
(24.2)
   Increase in employee-related costs, including labor and benefits, as a result of the
   impact from winter weather and storms, as compared to the first quarter of 2014
10.5
   Implementation of a new outage restoration program at CL&P
3.9
   All other operations and maintenance
2.6
Total Base Electric Distribution
(7.2)
Total Base Natural Gas Distribution
3.6
Total Tracked costs (Transmission and Electric and Natural Gas Distribution)
(2.7)
Total Distribution and Transmission
(6.3)
Other and eliminations:
  Integration costs
(2.5)
  All other (including eliminations)
(9.5)
Total Operations and Maintenance
$
(18.3)

~~The Operations and Maintenance expenses that are recovered through base electric distribution rates (and therefore impact earnings) decreased $6.9 million and $17.6 million, respectively, for~~Depreciationincreased in the ~~three and six months ended June 30, 2014,~~first quarter of 2015, as compared to the same ~~periods~~period in 2013. The Operations and Maintenance expenses that are recovered through cost tracking mechanisms (and therefore have no earnings impact) increased $14.4 million and $23.5 million, respectively, for the three and six months ended June 30, 2014, as compared to the same periods in 2013. These increases were primarily driven by an increase in bad debt expense ($4.2 million and $8.2 million, respectively) and higher operation and maintenance costs at the PSNH generation business due to the timing of planned outages ($4.2 million and $5.1 million, respectively) for the three and six months ended June 30, 2014, as compared to the same periods in 2013.

~~Depreciation~~~~decreased for the three and six months ended June 30, 2014, as compared to the same periods in 2013,~~ due primarily ~~to a decrease in CYAPC and YAEC decommissioning costs ($12.5 million and $25 million, respectively), partially offset by an increase related~~ to higher utility plant balances resulting from completed construction projects placed into service ~~($5 million~~ and ~~$10.6 million, respectively).~~an increase in depreciation rates at CL&P as a result of the distribution rate case effective December 1, 2014.

Amortization of Regulatory ~~Assets/(Liabilities),~~Assets, Net, ~~decreased for~~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, Net, increased in the ~~three and six months ended June 30, 2014,~~first quarter of 2015, as compared to the same ~~periods~~period in ~~2013,~~2014, due primarily to the following:

Three Months Ended

Six Months Ended
(Millions of Dollars)
Increase/(Decrease)

Increase/(Decrease)
Recovery of stranded costs at NSTAR Electric
$
(55.1)

$
(86.4)
Increases in the SCRC, ES and other amortizations at PSNH

(21.5)

(5.8)
Amortization of previously deferred congestion costs at CL&P

19.1

38.3
Other

(0.6)

(0.3)

$
(58.1)

$
(54.2)
(Millions of Dollars)
Increase/(Decrease)
NSTAR Electric (primarily 2014 Comprehensive Settlement Agreement and
  deferred transition costs)
$
(21.3)
CL&P (primarily storm cost recovery and energy supply and energy-related costs)
18.4
PSNH (primarily default energy service charge)
2.5
WMECO
3.5
Other
(0.4)
Total Amortization of Regulatory Assets, Net
$
2.7

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

4940

In connection with the 2014 Comprehensive Settlement Agreement, NSTAR Electric recognized an $11.7 million benefit in the first quarter of 2015, which was recorded as a reduction to amortization expense. The CL&P amount reflects an increase in storm cost recovery, which was approved and included in distribution rates effective December 1, 2014.

Energy Efficiency Programs, which are tracked costs, increased ~~for~~in the ~~three and six months ended June 30, 2014,~~first quarter of 2015, as compared to the same ~~periods~~period in ~~2013,~~2014, due primarily to an increase in energy efficiency costs in accordance with the three-year program guidelines established by the DPU at NSTAR ~~Electric and WMECO and expanded energy conservation programs at CL&P in 2014, partially offset by a decrease in the amortization of previously deferred costs at NSTAR~~ Electric. ~~All costs are fully recovered through approved tracking mechanisms and therefore do not impact earnings.~~

Taxes Other Than Income Taxes increased ~~for~~in the ~~three and six months ended June 30, 2014,~~first quarter of 2015, as compared to the same ~~periods~~period in ~~2013,~~2014, due primarily to an increase in property taxes ~~($9.1 million and $16.6 million, respectively)~~ as a result of both an increase in utility plant balances and property tax ~~rates, and an increase in the Connecticut gross earnings tax ($2.2 million and $8.2 million, respectively) attributable to an increase in retail revenues.~~rates.

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

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

~~Income Tax Expense~~

For the Three Months Ended June 30,

For the Six Months Ended June 30,

(Millions of Dollars)
2014

2013

Decrease

Percent

2014

2013

Increase

Percent

Income Tax Expense
$
77.8

$
95.6

$
(17.8)

(18.6)
%

$
219.3

$
216.1

$
3.2

1.5
%

~~Income Tax Expense decreased for the three months ended June 30, 2014,~~2015, as compared to the same period in ~~2013,~~2014, due primarily to ~~lower pre-tax earnings~~higher other interest expense ($~~2.5~~4.5 million) ~~and the tax benefit impact from the reserve recorded~~due primarily to interest on regulatory deferral mechanisms.

Other Income, Netincreased in the ~~second~~first quarter of ~~2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints ($22.1 million), partially offset by higher state taxes ($4.6 million) and various other tax impacts ($2.2 million).~~

~~Income Tax Expense increased for the six months ended June 30, 2014,~~2015, as compared to the same period in ~~2013,~~2014, due primarily to higher AFUDC related to equity funds ($1.9 million) and net gains on marketable securities ($1.6 million).

Income Tax Expense increased in the first quarter of 2015, as compared to the same period in 2014, due primarily to higher pre-tax earnings ($~~10.6~~10.1 million), and higher state taxes ($8.6 million), the absence of the favorable impact from the resolution of a state income tax audit in the first quarter of 2013 ($4.8 million), and various other tax impacts ($1.3 million), partially offset by the tax benefit impact from the reserve recorded as a result of the FERC ROE orders issued in the FERC base ROE complaints ($22.11.4 million).

5041

RESULTS OF OPERATIONS – THE CONNECTICUT LIGHT AND POWER COMPANY

The following provides the amounts and variances in operating revenues and expense line items ~~for~~in the ~~condensed~~ statements of income for CL&P for the three months ended March 31, 2015 and 2014 included in this Quarterly Report on Form ~~10-Q for the three and six months ended June 30, 2014 and 2013:~~10-Q:

Operating Revenues and Expenses

Operating Revenues and Expenses

For the Three Months Ended June 30,

For the Six Months Ended June 30,

(Millions of Dollars)
2014

2013

Increase/
(Decrease)

Percent

2014

2013

Increase/
(Decrease)

Percent

Operating Revenues
$
587.3

$
569.3

$
18.0

3.2
%

$
1,321.9

$
1,193.4

$
128.5

10.8
%
Operating Expenses:

Purchased Power and Transmission

199.8

184.8

15.0

8.1

481.2

414.1

67.1

16.2

Operations and Maintenance

131.8

123.8

8.0

6.5

241.3

232.6

8.7

3.7

Depreciation

46.6

45.1

1.5

3.3

92.7

87.6

5.1

5.8

Amortization of Regulatory Assets, Net

19.6

0.5

19.1

(a)

49.5

11.2

38.3

(a)

Energy Efficiency Programs

35.3

20.8

14.5

69.7

78.0

43.7

34.3

78.5

Taxes Other Than Income Taxes

62.1

57.5

4.6

8.0

129.1

117.7

11.4

9.7

Total Operating Expenses

495.2

432.5

62.7

14.5

1,071.8

906.9

164.9

18.2

Operating Income
$
92.1

$
136.8

$
(44.7)

(32.7)
%

$
250.1

$
286.5

$
(36.4)

(12.7)
%

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

Operating Revenues

CL&P's retail sales were as follows:

For the Three Months Ended June 30,

For the Six Months Ended June 30,

2014

2013

Decrease

Percent

2014

2013

Increase

Percent

Retail Sales in GWh
5,050

5,194

(144)

(2.8)
%

10,999

10,875

124

1.1
%

For the Three Months Ended March 31,

Increase/

(Millions of Dollars)
2015

2014

(Decrease)

Percent

Operating Revenues
$
804.9

$
734.6

$
70.3

9.6
%
Operating Expenses:

Purchased Power and Transmission

333.6

281.4

52.2

18.6

Operations and Maintenance

117.4

109.5

7.9

7.2

Depreciation

52.9

46.1

6.8

14.8

Amortization of Regulatory Assets, Net

48.3

29.9

18.4

61.5

Energy Efficiency Programs

42.8

42.7

0.1

0.2

Taxes Other Than Income Taxes

68.1

67.0

1.1

1.6

Total Operating Expenses

663.1

576.6

86.5

15.0

Operating Income

141.8

158.0

(16.2)

(10.3)

Interest Expense

36.6

34.2

2.4

7.0

Other Income, Net

2.2

1.0

1.2

(a)

Income Before Income Tax Expense

107.4

124.8

(17.4)

(13.9)

Income Tax Expense

38.2

45.5

(7.3)

(16.0)

Net Income
$
69.2

$
79.3

$
(10.1)

(12.7)
%

(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 March 31,

2015

2014

Increase

Percent

Retail Sales Volumes in GWh

5,994

5,949

45

0.8
%

CL&P's Operating Revenues increased by $70.3 million in the ~~second~~first quarter of ~~2014,~~2015, as compared to the same period in 2014.

Distribution revenues increased by $78.8 million as a result of ~~2013.~~increases in energy supply costs ($101.6 million) and the impact of increased rates on base distribution revenues ($29.2 million), which was primarily attributable to the impact of CL&P's base distribution rate case effective December 1, 2014. The increase in distribution revenues was partially offset by decreased costs associated with federally mandated congestion charges ($30.3 million), and a decrease in retail transmission revenues and competitive transition assessment charges. Energy supply costs were impacted by the overall New England wholesale energy supply market in which natural gas delivery costs are adversely impacting the cost of electric energy purchased for our retail customers. Energy supply costs, federally mandated congestion charges, retail transmission revenues and competitive transition assessment charges are recovered from customers in rates through cost tracking mechanisms and therefore have no impact on earnings.

Effective December 1, 2014, CL&P’s distribution revenues were decoupled from its sales volumes and CL&P no longer recognized LBR. The revenue decoupling mechanism provides a base amount of distribution revenues ($1.041 billion on an annual basis) and effectively breaks the relationship between revenues and customer electricity usage. Revenue decoupling mechanisms ensure the recovery of our approved base distribution revenue requirements. Therefore, changes in sales volumes have no impact on the level of base distribution revenue realized. In the first quarter of 2014, which was colder than normal, CL&P’s rates were not decoupled.

Transmission revenues decreased by $8.5 million due primarily ~~reflects~~to the impact of the $12.5 million reserve related to the March 2015 FERC ROE order, partially offset by the recovery of higher revenue requirements associated with ongoing investments in our transmission infrastructure.

Purchased Power and Transmission expense includes costs associated with purchasing electricity on behalf of ~~our~~CL&P's customers. ~~Fluctuations in these~~These energy supply costs are recovered from customers in ~~rates and therefore~~PURA-approved cost tracking mechanisms, which have no impact on ~~earnings. Partially offsetting this increase was~~earnings (tracked costs). Purchased Power and Transmission increased in the ~~impact of the reserve recorded during the second~~first quarter of ~~2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints. For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints"in this~~~~Management's Discussion and Analysis.~~ ~~In addition, retail sales volumes decreased 2.8 percent in the second quarter of 2014,~~2015, as compared to the same period in ~~2013,~~2014, due primarily to the following:

(Millions of Dollars)
Increase/(Decrease)
Purchased Power Costs
$
71.3
Transmission Costs
(18.2)
Other
(0.9)
Total Purchased Power and Transmission
$
52.2

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 ~~milder temperatures in late May and June of 2014.~~

~~CL&P's Operating Revenues increased in the first half of 2014, as compared~~providing electric generation service supply to ~~the first half of 2013.~~all customers that have not migrated to competitive energy suppliers. The increase ~~reflects higher retail sales volumes of 1.1 percent as a result of significantly colder weather~~ in ~~the first quarter of 2014, as compared~~purchased power was due primarily to ~~the same period in 2013, and the overall impact of~~ higher costs associated with the procurement of energy ~~supply. The energy~~ supply costs were impacted by higher natural gas transportation costs, which had an adverse impact on the cost of purchased electric energy for our retail customers. Fluctuations in energy supply costs are recovered from customers in rates and ~~therefore have no impact on earnings. Partially offsetting this increase was the impact of the reserve recorded during the second quarter of 2014~~increased load as a result of ~~the FERC ROE orders issued in the FERC base ROE complaints.~~

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

Three Months Ended

Six Months Ended
(Millions of Dollars)
Increase/(Decrease)

Increase/(Decrease)
GSC Supply Costs
$
3.2

$
104.4
Transmission Costs

5.4

11.8
Deferred Fuel Costs

26.8

(29.0)
Purchased Power Costs

(15.6)

(15.2)
Other

(4.8)

(4.9)

$
15.0

$
67.1

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

Operations and Maintenanceexpense includes tracked costs ~~that are recovered in rates through cost tracking mechanisms, which have no earnings impact (tracked costs),~~ and costs that are ~~recovered through~~part of base ~~electric~~ distribution rates ~~(and therefore impact earnings)~~with changes impacting earnings (non-tracked costs). Operations and Maintenance increased in the ~~second~~first quarter of ~~2014,~~2015, as compared to the same period in ~~2013,~~2014, driven by a ~~$5.2~~$6.7 million increase in ~~tracked~~non-tracked costs, ~~that have no earnings impact,~~ which was primarily attributable to ~~higher bad debt expense of $3.6 million. There was also~~ an increase in costs ~~that impact earnings of $2.8 million, which was primarily attributable to~~for the implementation of a new outage restoration program

42

that began in the second quarter of ~~$3.7 million,~~2014, higher ~~routine~~storm restoration costs and higher vegetation management costs, ~~of $3.7 million and higher bad debt expense of $1.3 million,~~ partially offset by lower ~~employee~~employee-related costs, ~~(including pension and~~including benefit ~~related costs) of $8.4 million.~~costs. Additionally, there was a $1.2 million increase in tracked costs, which have no earnings impact, that was primarily attributable to increased transmission expenses.

51

~~Operations and Maintenance~~Depreciation increased in the first ~~half~~quarter of ~~2014,~~2015, as compared to the same period in ~~2013, driven by a $9.6 million~~2014, due primarily to an increase in ~~costs~~depreciation rates as a result of the distribution rate case decision that ~~have no earnings impact, primarily attributable to higher bad debt expense of $7.2 million. Partially offsetting this increase~~ was ~~a decrease in costs that impact earnings of $0.9 million, primarily attributable to lower employee costs (including pension~~effective December 1, 2014 and benefit related costs) of $13.1 million, partially offset by the implementation of a new outage restoration program of $3.8 million, higher bad debt expense of $2.9 million and higher routine vegetation management costs of $3.4 million.

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

Amortization of Regulatory Assets, ~~Net~~Net¸increased ~~for~~in the ~~three and six months ended June 30, 2014,~~first quarter of 2015, as compared to the same ~~periods~~period in ~~2013,~~2014, due primarily to an increase in ~~amortization expense related to previously deferred congestion charges.~~

~~Energy Efficiency Programs~~~~increased for the three~~storm cost recovery, which was approved and ~~six months ended June 30,~~included in distribution rates effective December 1, 2014, as ~~compared~~well as energy supply and energy-related costs that can fluctuate from period to period based on the ~~same periods~~timing of costs incurred and related rate changes to recover these costs. Fluctuations in ~~2013, due primarily to expanded~~ energy ~~conservation programs~~supply and energy-related costs, which are the primary drivers in ~~2014. All costs~~amortization, are ~~fully~~ recovered ~~through PURA-approved tracking mechanisms~~from customers in rates and ~~therefore do not~~have no impact on earnings.

Taxes Other Than Income Taxes increased ~~for~~in the ~~three and six months ended June 30, 2014,~~first quarter of 2015, as compared to the same ~~periods~~period in ~~2013,~~2014, due primarily to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates ($3.9 million and $7.8 million, respectively). In addition, there was an increase in the Connecticut gross earnings tax attributable to an increase in retail revenues ($1.1 million and $4.7 million, respectively).rates.

Interest Expenseincreased ~~$3.5 million and $8 million for~~in the ~~three and six months ended June 30, 2014,~~first quarter of 2015, as compared to the same ~~periods~~period in ~~2013, respectively,~~2014, due primarily to ~~the absence in 2014 of the favorable impact from the resolution of a state income tax audit in the first quarter of 2013 ($6 million for the six months),~~ an increase in other interest expense due to interest on regulatory deferral mechanisms ($~~1 million and $2.2 million, respectively)~~1.8 million), and an increase in interest on long-term debt ($~~2 million and $2.2 million, respectively).~~0.6 million) as a result of a new debt issuance in April 2014.

Other Income, Net~~decreased $2.9 million~~increased in the first ~~six months~~quarter of ~~2014,~~2015, as compared to the same period in ~~2013,~~2014, due primarily to ~~lower unrealized gains on the assets supporting the deferred compensation plans~~higher AFUDC related to equity funds ($~~1.4 million) and lower AFUDC-Equity ($1.2~~0.8 million).

Income Tax Expense

For the Three Months Ended June 30,

For the Six Months Ended June 30,

(Millions of Dollars)
2014

2013

Decrease

Percent

2014

2013

Decrease

Percent

Income Tax Expense
$
20.4

$
37.8

$
(17.4)

(46.0)
%

$
65.9

$
77.0

$
(11.1)

(14.4)
%

~~Income Tax Expense~~ decreased ~~for~~in the ~~three and six months ended June 30, 2014,~~first quarter of 2015, as compared to the same ~~periods~~period in ~~2013,~~2014, due primarily to lower pre-tax earnings ($~~5.8 million~~6.1 million) and ~~$4.2 million, respectively) and the tax benefit impact from the FERC ROE orders issued in the second quarter of 2014~~lower state taxes ($12.8 million for the three and six months), partially offset by the absence in 2014 of the state audit closure benefit impact ($2.9 million for the six months) and various other tax impacts ($1.2 million and $3.0 million, respectively)1.1 million).

EARNINGS SUMMARY

For the Three Months Ended June 30,

For the Six Months Ended June 30,

(Millions of Dollars)
2014

2013

Decrease

Percent

2014

2013

Decrease

Percent

Net Income
$
37.4

$
67.9

$
(30.5)

(44.9)
%

$
116.7

$
152.9

$
(36.2)

(23.7)
%

CL&P's ~~second~~earnings decreased $10.1 million in the first quarter ~~2014 earnings were lower than the same period in 2013 due primarily to the establishment~~ of ~~an $18.5 million after-tax reserve related to the June 2014 FERC ROE orders, lower retail sales as a result of milder temperatures in late May and June of 2014,~~2015, as compared to the same period in ~~2013, higher property tax expense, increased interest expense relating~~2014, due primarily to a $7.9 million after-tax reserve related to the March 2015 FERC ROE order, an increase in operations and maintenance costs, which was primarily attributable to an ~~April~~increase in costs for the implementation of a new outage restoration program that began in the second quarter of 2014, ~~financing,~~higher storm restoration costs and higher vegetation management costs, and higher depreciation and property tax expense. Partially offsetting these unfavorable earnings impacts were ~~increased investments in the transmission infrastructure.~~

~~For the six months ended June 30, 2014, CL&P's earnings decreased, as compared to the same period in 2013,~~higher distribution revenues due primarily to the ~~establishment~~impact of the ~~after-tax reserve related to the June~~December 1, 2014 FERC ROE orders, higher property tax expense and increased interest expense relating to an April 2014 financing. Partially offsetting these unfavorable earnings impacts were higher retail electric sales as a result of colder weather in the first quarter of 2014 and increased investments in the transmission infrastructure.

52base distribution rate increase.

LIQUIDITY

CL&P had cash flows provided by operating activities of ~~$275.4~~$133.9 million in the first ~~half~~quarter of ~~2014,~~2015, compared with ~~$178.2~~$95.5 million in the first ~~half~~quarter of ~~2013.~~2014. The improved operating cash flows were due primarily to $65.4 million in DOE Phase II Damages proceeds received on June 1, 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, the absence of cash disbursements for major storm restoration costs and an increase in regulatory overrecoveries, ~~partially offset by~~ income tax ~~payments~~refunds of ~~$3.8~~$122.4 million in the first ~~half~~quarter of ~~2014, as~~2015, compared towith income tax refunds of $6$11.7 million in the first ~~half~~quarter of ~~2013, and an unfavorable cash flow~~2014. Partially offsetting this favorable impact ~~relating to~~was the timing of regulatory recoveries, resulting from the increase in federally mandated congestion charges, along with timing of collections and payments related to our working capital items, including accounts receivable ~~payments made~~and accounts payable. Accounts receivable increased due primarily to ~~affiliated companies~~the basic service rate increase effective January 1, 2015 and the increase in ~~the second quarter of~~distribution rates effective December 1, 2014.

Investments in Property, Plant and Equipment on the ~~accompanying~~ statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension expense. In the first ~~half~~quarter of ~~2014,~~2015, investments for CL&P were ~~$221.4~~$127.6 million.

On April ~~24, 2014,~~1, 2015, CL&P ~~issued $250~~repaid at maturity the $100 million ~~of 4.30~~5.00 percent ~~2014~~ Series A First and Refunding Mortgage Bonds ~~due~~using short-term borrowings. On April 1, 2015, CL&P also redeemed the $62 million 1996A Series 1.55 percent PCRBs that were subject to ~~mature in April 2044. The proceeds, net of issuance costs, were used to repay short-term~~mandatory tender, using short term borrowings.

~~Effective July 23, 2014, NU~~ES parent, and certain of its subsidiaries, including CL&P, ~~amended their joint~~are parties to a five-year $1.45 billion revolving credit facility ~~to extend the expiration date an additional year to~~that expires September 6, 2019. The revolving credit facility is ~~to be~~ used primarily to backstop NUES parent's $1.45 billion commercial paper program. The commercial paper program allows NUES parent to issue commercial paper as a form of short-term debt with intercompany loans to ~~its~~certain subsidiaries, including CL&P. As of ~~June 30, 2014 and December~~March 31, ~~2013,~~2015, there were intercompany loans from NUES parent of ~~$6.4~~$190.1 million ~~and $287.3~~to CL&P. As of December 31, 2014, there were intercompany loans from ES parent of $133.4 million ~~respectively,~~ to CL&P.

~~Additional financing~~Financing activities in the first ~~half~~quarter of ~~2014~~2015 included ~~$85.6~~$49 million in common stock dividends paid to NUES parent.

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

5343

RESULTS OF OPERATIONS – NSTAR ELECTRIC COMPANY AND SUBSIDIARY

The following provides the amounts and variances in operating revenues and expense line items ~~for~~in the ~~condensed consolidated~~ statements of income for NSTAR Electric for the three months ended March 31, 2015 and 2014 included in this Quarterly Report on Form ~~10-Q for the six months ended June 30, 2014 and 2013:~~10-Q:

Operating Revenues and Expenses

For the Six Months Ended June 30,

(Millions of Dollars)
2014

2013

Increase/

Percent

(Decrease)

Operating Revenues
$
1,227.7

$
1,162.7

$
65.0

5.6
%
Operating Expenses:

Purchased Power and Transmission

562.0

403.9

158.1

39.1

Operations and Maintenance

164.9

180.2

(15.3)

(8.5)

Depreciation

93.6

90.9

2.7

3.0

Amortization of Regulatory Assets, Net

14.1

100.5

(86.4)

(86.0)

Amortization of Rate Reduction Bonds

-

15.0

(15.0)

(100.0)

Energy Efficiency Programs

88.6

102.4

(13.8)

(13.5)

Taxes Other Than Income Taxes

64.6

62.7

1.9

3.0

Total Operating Expenses

987.8

955.6

32.2

3.4

Operating Income
$
239.9

$
207.1

$
32.8

15.8
%

Operating Revenues

NSTAR Electric's retail sales were as follows:

For the Six Months Ended June 30,

2014

2013

Decrease

Percent

Retail Sales in GWh

10,183

10,198

(15)

(0.1)
%

For the Three Months Ended March 31,

Increase/

(Millions of Dollars)
2015

2014

(Decrease)

Percent

Operating Revenues
$
766.8

$
666.2

$
100.6

15.1
%
Operating Expenses:

Purchased Power and Transmission

401.9

319.1

82.8

25.9

Operations and Maintenance

75.8

85.9

(10.1)

(11.8)

Depreciation

48.8

46.6

2.2

4.7

Amortization of Regulatory Assets/(Liabilities), Net

(5.6)

15.7

(21.3)

(a)

Energy Efficiency Programs

55.4

48.3

7.1

14.7

Taxes Other Than Income Taxes

31.0

32.2

(1.2)

(3.7)

Total Operating Expenses

607.3

547.8

59.5

10.9

Operating Income

159.5

118.4

41.1

34.7

Interest Expense

20.4

21.1

(0.7)

(3.3)

Other Income, Net

0.6

-

0.6

(a)

Income Before Income Tax Expense

139.7

97.3

42.4

43.6

Income Tax Expense

56.1

39.2

16.9

43.1

Net Income
$
83.6

$
58.1

$
25.5

43.9
%

(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 Three Months Ended March 31,

2015

2014

Increase

Percent

Retail Sales Volumes in GWh

5,433

5,358

75

1.4
%

NSTAR Electric's Operating Revenues increased by $100.6 million in the first ~~half~~quarter of ~~2014,~~2015, as compared to the ~~first half~~same period in 2014.

Distribution revenues increased due primarily to an increase in rates related to the recovery of ~~2013. The increase primarily reflects the overall impact of higher~~ costs associated with the procurement of energy ~~supply. Our~~supply, which increased $110.5 million, and increased cost recovery related to our energy efficiency programs. The energy supply costs were impacted by ~~higher~~the overall wholesale electricity market in New England in which natural gas ~~transportation~~delivery costs ~~which had an adverse impact on~~are adversely impacting the cost of ~~purchased~~ electric energy purchased for our retail customers. ~~Fluctuations~~In addition, base distribution revenues increased as a result of the impact from the recognition of LBR ($3.8 million) and the colder winter weather in 2015 ($2.6 million). These increases were partially offset by decreased retail transmission revenues and transition cost recovery revenues. Energy supply costs, energy efficiency program costs, retail transmission revenues and transition cost recovery revenues are recovered from customers in rates through cost tracking mechanisms and therefore have no impact on earnings.

Transmission revenues increased $7.1 million in the first quarter of 2015, as compared to the same period in 2014, due primarily to the recovery of higher revenue requirements associated with ongoing investments in our transmission infrastructure, partially offset by the impact of a $2.4 million reserve related to the March 2015 FERC ROE order. For further information on the March 2015 FERC ROE order, see "FERC Regulatory Issues – FERC ROE Complaints" in thisManagement's Discussion and Analysis of Financial Conditions and Results of Operations.

Additionally, in connection with the 2014 Comprehensive Settlement Agreement, NSTAR Electric recognized an $11 million benefit in the first quarter of 2015, which was recorded as an increase to operating revenues. For further information, see "Regulatory Developments and Rate Matters – Massachusetts – 2014 Comprehensive Settlement Agreement" in thisManagement's Discussion and Analysis of Financial Conditions and Results of Operations.

Purchased Power and Transmissionexpense includes costs associated with purchasing electricity on behalf of NSTAR Electric's customers. These energy supply costs are recovered from customers in ~~rates and therefore~~DPU-approved cost tracking mechanisms which have no impact on earnings. Partially offsetting this increase was the impact of the reserve recorded during the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints. For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints"in this~~Management's Discussion~~earnings (tracked costs). Purchased Power and ~~Analysis.~~ Additionally, stranded cost recovery revenues decreased during the period, reflecting the full collection in 2013 of previously deferred costs, as well as the full amortization of RRBs. Base distribution revenues were relatively flatTransmission increased in the first ~~half~~quarter of ~~2014,~~2015, as compared to the same period in ~~2013, reflecting comparable sales, which was due primarily to colder weather in the first quarter of~~ 2014, offset by milder temperatures in late May and June of 2014 and customer savings due to the impact of its energy efficiency programs. NSTAR Electric is permitted to bill customers for lost base revenues related to reductions in sales volume as a result of their energy efficiency. In the first half of 2014, base distribution revenues increased $5.4 million, compared to the first half of 2013 (including the impact from the recognition of lost base revenues).

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

(Millions of Dollars)
~~Six Months Ended~~
Increase/(Decrease)
~~Basic Service~~Purchased Power Costs
$
~~115.4~~99.0
Transmission Costs

~~26.4~~ (16.1)
~~Purchased Power Costs~~Other

~~20.1~~ (0.1)
~~Deferred Fuel Costs~~
~~(3.8)~~
Total Purchased Power and Transmission
$
~~158.1~~82.8

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

Operations and Maintenanceexpense includes tracked costs ~~that are recovered in rates through cost tracking mechanisms, which have no earnings impact (tracked costs),~~ and costs that are ~~recovered through~~part of base ~~electric~~ distribution rates ~~(and therefore impact earnings)~~with changes impacting earnings (non-tracked costs). Operations and Maintenance decreased in the first ~~half~~quarter of ~~2014,~~2015, as compared to the ~~first half of 2013,~~same period in 2014, driven by ~~a $21.5~~an $11.2 million reduction in non-tracked costs, ~~that impact earnings (primarily~~which was primarily attributable to ~~lower employee costs and benefit costs~~the resolution of ~~$15.7 million and lower storm costs of $3 million. Partially offsetting this decrease was~~the basic service bad debt adder mechanism ($24.2 million), partially offset by an increase in labor and employee benefits expense, as a result of the impact from winter weather and storms, as

44

compared to the first quarter of 2014. Tracked costs, ~~that~~which have no earnings impact, ~~of $6.2~~increased $1.1 million, ~~(primarily~~which was primarily attributable to ~~higher storm costs of $3 million).~~increased transmission expenses.

Depreciationincreased in the first ~~half~~quarter of ~~2014,~~2015, as compared to the ~~first half of 2013,~~same period in 2014, due primarily to higher utility plant balances resulting from completed construction projects placed into service.

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

~~Amortization of Rate Reduction Bonds~~~~decreased in~~tracked transition costs for the first ~~half~~quarter of ~~2014, as compared to the first half of 2013, due to the maturity of the RRBs in March 2013.~~

54

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

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

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

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

~~Income Tax Expense~~

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

2013

Increase

Percent

Income Tax Expense
$
79.7

$
68.9

$
10.8

15.7
%

~~Income Tax Expense increased in the first half of 2014,~~2015, as compared to the same period in ~~2013,~~2014. Fluctuations in these costs are recovered from customers in rates and have no impact on earnings. Additionally, in connection with the 2014 Comprehensive Settlement Agreement, NSTAR Electric recognized an $11.7 million benefit in the first quarter of 2015, which was recorded as a reduction to amortization expense. For further information, see "Regulatory Developments and Rate Matters – Massachusetts – 2014 Comprehensive Settlement Agreement" in thisManagement's Discussion and Analysis of Financial Conditions and Results of Operations.

Energy Efficiency Programs, which are tracked costs, increased in the first quarter of 2015, as compared to the same period in 2014, due primarily to an increase in energy efficiency costs incurred in accordance with the three-year program guidelines established by the DPU.

Interest Expense decreased in the first quarter of 2015, as compared to the same period in 2014, due primarily to a decrease in interest on long-term debt ($2.1 million), partially offset by an increase in other interest expense in connection with the 2014 Comprehensive Settlement Agreement ($1 million).

Income Tax Expense increased in the first quarter of 2015, as compared to the same period in 2014, due primarily to higher pre-tax earnings ($~~11.6~~14.8 million) and higher state taxes ($~~3.5 million), partially offset by the tax benefit impact from the FERC ROE orders issued in the second quarter of 2014 ($4.1~~2.3 million).

EARNINGS SUMMARY

For the Six Months Ended June 30,

(Millions of Dollars)
2014

2013

Increase

Percent

Net Income
$
118.2

$
106.2

$
12.0

11.3
%

~~In the first half of 2014,~~ NSTAR Electric's earnings increased $25.5 million in the first quarter of 2015, as compared to the same period in ~~2013,~~2014, due primarily to ~~lower operations~~the resolution of the basic service bad debt adder mechanism ($14.5 million), the favorable impact associated with the 2014 Comprehensive Settlement Agreement ($13 million), higher LBR and ~~maintenance expenses attributed to lower employee costs, benefit costs and lower storm costs. Partially offsetting these~~higher retail sales volumes. These favorable earnings impacts were partially offset by an increase in operations and maintenance costs due primarily to an increase in labor and employee benefits expense as a result of the ~~establishment of~~impact from winter weather and storms, a ~~$6.1~~$1.4 million after-tax reserve related to the ~~June 2014~~March 2015 FERC ROE ~~orders~~order, and higher depreciation ~~and property tax expenses.~~expense.

LIQUIDITY

NSTAR Electric had cash flows provided by operating activities of ~~$387.7~~$221.3 million in the first ~~half~~quarter of ~~2014,~~2015, compared with ~~$91.6~~$191.4 million in the first ~~half~~quarter of ~~2013.~~2014. The ~~increase in~~improved operating cash flows ~~was~~were due primarily to ~~the absence of cash disbursements for major storm restoration costs associated with the February 2013 blizzard,~~changes in working capital items, including the timing of ~~collections of~~ accounts ~~receivables~~receivable from affiliated companies, ~~$29.1~~and income tax refunds of $84.6 million in ~~DOE Phase II Damages proceeds received on June 1, 2014 from~~ the ~~Yankee Companies associated~~first quarter of 2015, compared with ~~the spent nuclear fuel litigation, a decrease in~~ income tax payments of $17.3 million in the first ~~half~~quarter of ~~2014, as compared to the first half of 2013, and the absence of Pension Plan cash contributions in the first half of 2014, as compared to the first half of 2013. These~~2014. Partially offsetting these favorable cash flow impacts were ~~partially offset by~~ the ~~absence~~timing of regulatory recoveries, resulting from the increase in purchased power costs, ~~recovered in rates~~along with the timing of collections related to ~~the RRBs that were fully amortized~~our accounts receivable. Accounts receivable increased due primarily to higher sales volumes in the first quarter of ~~2013.~~2015 as a result of colder weather and an increase in basic service rates effective January 1, 2015.

~~Effective July 23, 2014,~~ NSTAR Electric ~~amended its~~has a five-year $450 million revolving credit facility ~~to extend the expiration date an additional year to~~that expires September 6, 2019. This facility serves to backstop NSTAR Electric's existing $450 million commercial paper program. As of ~~June 30, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, NSTAR Electric had ~~$194.5~~$215.5 million and ~~$103.5~~$302 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving ~~$255.5~~$234.5 million and ~~$346.5~~$148 million ~~respectively,~~ of available borrowing ~~capacity.~~capacity as of March 31, 2015 and December 31, 2014, respectively. The weighted-average interest rate on these borrowings as of ~~June 30, 2014~~March 31, 2015 and December 31, ~~2013~~2014 was ~~0.16~~0.35 percent and ~~0.13~~0.27 percent, respectively, which is generally based on A2/P1 rated commercial paper.

5545

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

The following provides the amounts and variances in operating revenues and expense line items ~~for~~in the ~~condensed consolidated~~ statements of income for PSNH for the three months ended March 31, 2015 and 2014 included in this Quarterly Report on Form ~~10-Q for the six months ended June 30, 2014 and 2013:~~10-Q:

Operating Revenues and Expenses

For the Six Months Ended June 30,

Increase/

(Millions of Dollars)
2014

2013

(Decrease)

Percent

Operating Revenues
$
511.5

$
489.9

$
21.6

4.4
%

Operating Expenses:

Purchased Power, Fuel and Transmission

183.6

151.1

32.5

21.5

Operations and Maintenance

132.5

122.1

10.4

8.5

Depreciation

48.7

45.5

3.2

7.0

Amortization of Regulatory Assets/(Liabilities), Net

(7.8)

(2.0)

(5.8)

(a)

Amortization of Rate Reduction Bonds

-

19.8

(19.8)

(100.0)

Energy Efficiency Programs

7.1

7.1

-

-

Taxes Other Than Income Taxes

34.3

33.9

0.4

1.2

Total Operating Expenses

398.4

377.5

20.9

5.5

Operating Income
$
113.1

$
112.4

$
0.7

0.6
%

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

Operating Revenues

PSNH's retail sales were as follows:

For the Six Months Ended June 30,

2014

2013

Increase

Percent

Retail Sales in GWh
3,909

3,837

72

1.9
%

For the Three Months Ended March 31,

Increase/

(Millions of Dollars)
2015

2014

(Decrease)

Percent

Operating Revenues
$
284.8

$
299.8

$
(15.0)

(5.0)
%

Operating Expenses:

Purchased Power, Fuel and Transmission

99.6

115.3

(15.7)

(13.6)

Operations and Maintenance

58.4

62.2

(3.8)

(6.1)

Depreciation

25.6

24.2

1.4

5.8

Amortization of Regulatory Assets, Net

15.1

12.6

2.5

19.8

Energy Efficiency Programs

3.8

3.8

-

-

Taxes Other Than Income Taxes

19.1

17.7

1.4

7.9

Total Operating Expenses

221.6

235.8

(14.2)

(6.0)

Operating Income

63.2

64.0

(0.8)

(1.3)

Interest Expense

11.3

12.0

(0.7)

(5.8)

Other Income, Net

0.4

0.3

0.1

33.3

Income Before Income Tax Expense

52.3

52.3

-

-

Income Tax Expense

20.3

19.7

0.6

3.0

Net Income
$
32.0

$
32.6

$
(0.6)

(1.8)
%

Operating Revenues

PSNH's retail sales volumes were as follows:

For the Three Months Ended March 31,

2015

2014

Decrease

Percent

Retail Sales Volumes in GWh

2,067

2,076

(9)

(0.5)
%

PSNH's Operating Revenues ~~increased in the first half of 2014, as compared to the first half of 2013, due primarily to an increase of 1.9 percent in retail sales as a result of the colder weather~~decreased $15 million in the first quarter of ~~2014,~~2015, as compared to the same period in ~~2013.~~2014. The ~~average daily temperature~~decrease primarily relates to a $6.8 million reduction in ~~New Hampshire~~wholesale generation revenues, which impact the timing of the recovery of generation and energy supply costs from customers. In addition, stranded costs revenues decreased $5 million in the first quarter of 2015, as compared to the same period in 2014 and there was ~~over five degrees lower than~~the impact of a $1 million reserve related to the March 2015 FERC ROE order recorded in the first quarter of ~~2013. In addition,~~2015. Base distribution revenues increased ~~due~~$1.1 million, as compared to the ~~overall impact~~first quarter of ~~higher~~2014, as a result of the colder winter weather in 2015 and its impacts on residential retail sales.

Purchased Power, Fuel and Transmissionexpense includes costs associated with ~~the procurement~~PSNH's generation of ~~energy supply. The energy supply costs were impacted by higher natural gas transportation costs, which had an adverse impact~~electricity as well as purchasing electricity on ~~the cost~~behalf of ~~purchased electric energy for our retail~~its customers. ~~Fluctuations in~~These generation and energy supply costs are recovered from customers in ~~rates and therefore~~NHPUC-approved cost tracking mechanisms, which have no impact on earnings. Also reflected in the revenue increase were increases of $6.4 million related to NHPUC-approved distribution rate increases effective July 1, 2013 and increases in transmission revenues as a result of the recovery of higher transmission expenses including ongoing investments in our transmission infrastructure, partially offset by the impact of the reserve recorded during the second quarter of 2014 as a result of the FERC ROE orders issued in the FERC base ROE complaints. For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints"in this~~Management's Discussion and Analysis.~~

earnings (tracked costs). Purchased Power, Fuel and Transmission ~~increased~~ decreased in the first ~~half~~quarter of ~~2014,~~2015, as compared to the ~~first half of 2013,~~same period in 2014, due primarily to the following:

(Millions of Dollars)
Increase/(Decrease)
Generation Fuel Costs
$
~~35.2~~
~~Renewable Energy Costs~~
~~9.9~~
~~Transmission Costs~~
~~4.7~~ (12.7)
Purchased Power Costs

~~(19.2)~~(4.6)
Other

~~1.9~~1.6
Total Purchased Power, Fuel and Transmission
$
~~32.5~~ (15.7)

PSNH procures power through its own generation, long-term power supply contracts and short-term purchases and spot purchases in the competitive New England wholesale power market. The ~~increase~~decrease in generation fuel costs was due primarily to ~~an increase~~a decrease in the amount of electricity generated by PSNH ~~facilities. The increase~~facilities and a decrease in renewable energy costs was a result of lower regional greenhouse gas initiative auction proceeds, partially offset by lower renewable energy requirements set by the NHPUC. The increase in transmission costs was as a result of an increasefuel prices in the ~~retail transmission cost deferral, which reflects the actual costs~~first quarter of ~~transmission service~~2015, as compared to ~~estimated amounts billed to customers~~. the same period in 2014. The decrease in purchased power costs was ~~a result~~due to lower power prices of ~~additional customer migration~~short-term and spot purchases made in the wholesale power market in the first quarter of 2015, as compared to ~~third party suppliers. Purchased Power, Fuel and Transmission costs are included~~the same period in ~~NHPUC-approved tracking mechanisms and do not impact earnings.~~2014.

Operations and Maintenanceexpense includes tracked costs and costs that are ~~recovered~~part of base distribution rates with changes impacting earnings (non-tracked costs). Operations and Maintenance decreased in ~~rates through cost tracking mechanisms,~~the first quarter of 2015, as compared to the same period in 2014, driven by a $2.1 million reduction in tracked costs, which have no earnings impact, ~~(tracked costs),~~ and a $1.7 million reduction in non-tracked costs, ~~that are recovered through base electric distribution rates (and therefore impact earnings). Operations and Maintenance increased in the first half~~both of ~~2014, as compared to the first half of 2013, driven by an $8 million increase in costs that have no earnings impact (primarily~~which were primarily attributable to ~~higher operations and maintenance costs at the generation business of $5.1 million due to the timing of planned outages and higher bad debt expense of $1 million, partially offset by~~ lower ~~employee~~employee-related costs, including ~~pension and~~ benefit ~~related costs, of $2.4 million). Additionally, there was an increase in costs that impact earnings of $2.4 million.~~costs.

Depreciationincreased in the first ~~half~~quarter of ~~2014,~~2015, as compared to the ~~first half of 2013,~~same period in 2014, due primarily to higher utility plant balances resulting from completed construction projects placed into service.

Amortization of Regulatory ~~Assets/(Liabilities),~~Assets, Net, reflects an increase in the recovery of the default energy service charge and other amortizations for the first quarter of 2015, as compared to the same period in 2014. Fluctuations in these costs are recovered from customers in rates and have no impact on earnings.

Taxes Other Than Income Taxesincreased in the first ~~half~~quarter of ~~2014,~~2015, as compared to the ~~first half of 2013,~~same period in 2014, due primarily to ~~increases~~an increase in ~~the stranded cost recovery charge, default energy service, and other amortizations~~property taxes as a result of ~~$1.7 million, $0.2 million, and $3.9 million, respectively.~~ an increase in utility plant balances.

5646

~~Amortization of Rate Reduction Bonds~~Income Tax Expense ~~decreased~~increased in the first ~~half~~quarter of ~~2014,~~2015, as compared to the ~~first half of 2013, due to the maturity of the RRBs~~same period in ~~May 2013.~~

~~Income Tax Expense~~

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

2013

Change

Percent

Income Tax Expense
$
34.6

$
34.6

$
-

-
%

~~Income Tax Expense was relatively flat in the first half of~~ 2014, ~~as compared to the first half of 2013,~~ due primarily to ~~higher pre-tax earnings~~lower permanent tax impacts ($~~1.5 million), offset by the tax benefit impact from the FERC ROE orders issued in the second quarter of 2014 ($1.5~~0.6 million).

EARNINGS SUMMARY

For the Six Months Ended June 30,

(Millions of Dollars)
2014

2013

Increase

Percent

Net Income
$
56.7

$
56.2

$
0.5

0.1
%

InPSNH's earnings decreased $0.6 million in the first ~~half~~quarter of ~~2014, PSNH's earnings increased,~~2015, as compared to the same period in ~~2013,~~2014, due primarily to higher distribution retail revenues, which were favorably impacted by the PSNH annualized distribution rate increases effective July 1, 2013, and higher retail electric sales. Partially offsetting these favorable earnings impacts were the establishment of a $2$0.6 million after-tax reserve related to the ~~June 2014~~March 2015 FERC ROE ~~orders,~~order, higher depreciation expense and higher ~~depreciation~~property tax expense. Partially offsetting these unfavorable earnings impacts were lower operations and maintenance costs primarily attributable to lower employee-related costs.

LIQUIDITY

PSNH had cash flows provided by operating activities of ~~$142.4~~$113.9 million in the first ~~half~~quarter of ~~2014,~~2015, compared with ~~$138.7~~$129.3 million in the first ~~half~~quarter of ~~2013.~~2014. The ~~improved~~decrease in operating cash flows ~~were~~was due primarily to ~~$13.1 million in DOE Phase II Damages proceeds received on June 1, 2014 from~~ the ~~Yankee Companies associated with the spent nuclear fuel litigation, the absence~~timing of ~~approximately $45 million in NUSCO Pension Plan cash contributions in the first half of 2014,~~collections and payments related to our working capital items, including accounts receivable, and the ~~favorable impact~~timing of ~~the 2010 rate case settlement related to the additional increase to annualized rates that was effective July 1, 2013~~. ~~These favorable~~our regulatory recoveries, which were in a net underrecovery position. Partially offsetting these unfavorable cash flow impacts were ~~partially offset by~~income tax refunds of $1.8 million in the first quarter of 2015, compared with income tax payments of ~~$28.8~~$16.1 million in the first ~~half of 2014, compared with income tax refunds of $12.1 million in the first half of 2013, and the absence of costs recovered in rates related to the RRBs that were fully amortized in the second~~ quarter of ~~2013.~~2014.

5747

RESULTS OF OPERATIONS – WESTERN MASSACHUSETTS ELECTRIC COMPANY

The following provides the amounts and variances in operating revenues and expense line items ~~for~~in the ~~condensed~~ statements of income for WMECO for the three months ended March 31, 2015 and 2014 included in this Quarterly Report on Form ~~10-Q for the six months ended June 30, 2014 and 2013:~~10-Q:

Operating Revenues and Expenses

For the Six Months Ended June 30,

Increase/

(Millions of Dollars)
2014

2013

(Decrease)

Percent

Operating Revenues
$
245.7

$
240.0

$
5.7

2.4
%
Operating Expenses:

Purchased Power and Transmission

87.1

72.3

14.8

20.5

Operations and Maintenance

46.3

44.1

2.2

5.0

Depreciation

20.6

18.3

2.3

12.6

Amortization of Regulatory Assets, Net

0.7

0.8

(0.1)

(12.5)

Amortization of Rate Reduction Bonds

-

7.8

(7.8)

(100.0)

Energy Efficiency Programs

22.1

16.2

5.9

36.4

Taxes Other Than Income Taxes

16.5

12.5

4.0

32.0

Total Operating Expenses

193.3

172.0

21.3

12.4

Operating Income
$
52.4

$
68.0

$
(15.6)

(22.9)
%

Operating Revenues

WMECO's retail sales were as follows:

For the Six Months Ended June 30,

2014

2013

Decrease

Percent

Retail Sales in GWh

1,793

1,798

(5)

(0.2)
%

For the Three Months Ended March 31,

Increase/

(Millions of Dollars)
2015

2014

(Decrease)

Percent

Operating Revenues
$
152.9

$
137.4

$
15.5

11.3
%
Operating Expenses:

Purchased Power and Transmission

69.7

49.4

20.3

41.1

Operations and Maintenance

19.8

22.6

(2.8)

(12.4)

Depreciation

10.4

10.3

0.1

1.0

Amortization of Regulatory Assets, Net

3.9

0.4

3.5

(a)

Energy Efficiency Programs

11.1

11.9

(0.8)

(6.7)

Taxes Other Than Income Taxes

9.4

8.1

1.3

16.0

Total Operating Expenses

124.3

102.7

21.6

21.0

Operating Income

28.6

34.7

(6.1)

(17.6)

Interest Expense

6.8

5.6

1.2

21.4

Other Income, Net

0.5

0.6

(0.1)

(16.7)

Income Before Income Tax Expense

22.3

29.7

(7.4)

(24.9)

Income Tax Expense

9.1

11.6

(2.5)

(21.6)

Net Income
$
13.2

$
18.1

$
(4.9)

(27.1)
%

(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 Three Months Ended March 31,

2015

2014

Decrease

Percent

Retail Sales Volumes in GWh

955

965

(10)

(1.1)
%

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

WMECO's Operating Revenues increased $15.5 million in the first quarter of 2015, as compared to the same period in 2014. The increase primarily reflects an increase in rates related to the recovery of costs associated with the procurement of energy supply, which increased $24.2 million. The energy supply costs were impacted by the overall wholesale electricity market in New England in which natural gas delivery costs are adversely impacting the cost of electric energy purchased for our retail customers. Energy supply costs are recovered from customers in rates through cost tracking mechanisms and therefore have no impact on earnings. Partially offsetting the increase was the impact of the $4.1 million reserve related to the March 2015 FERC ROE order, and a $3.9 million decrease in revenues that impacts earnings due to the absence of a 2014 wholesale billing adjustment.

For further information on the March 2015 FERC ROE order, see "FERC Regulatory Issues – FERC ROE Complaints" in thisManagement's Discussion and Analysis of Financial Conditions and Results of Operations.

Purchased Power and Transmission~~increased~~expense includes costs associated with the procurement of energy supply 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 Transmissionincreased in the first ~~half~~quarter of ~~2014,~~2015, as compared to the ~~first half of 2013,~~same period in 2014, due primarily to anthe following:

(Millions of Dollars)
Increase/(Decrease)
Purchased Power Costs
$
23.2
Transmission Costs
(2.9)
Total Purchased Power and Transmission
$
20.3

Included in purchased power are the costs associated with WMECO's basic service charge and deferred energy supply costs. The basic service charge recovers energy-related costs incurred as a result of providing electric generation service supply to all customers that have not migrated to third party suppliers. The increase in ~~supplier contract prices~~purchased power was due primarily to higher costs associated with the procurement of energy supply and ~~an increase in~~increased load as a result of customers returning to ~~default~~basic service from third party ~~suppliers ($13.9 million)and an increase~~suppliers. The decrease in transmission costs ~~($5.7 million)~~was as a result of ~~an increase~~a decrease in the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers. Partially offsetting this increase was the impact of the change in deferred fuel costs ($2.4 million) due primarily to higher average electric supply prices, as compared to the prices projected when basic service rates were set. Purchased Power and Transmission costs are included in DPU-approved tracking mechanisms and do not impact earnings.

Operations and Maintenanceexpense includes tracked costs and costs that are ~~recovered~~part of base distribution rates with changes impacting earnings (non-tracked costs). Operations and Maintenance decreased in ~~rates through cost tracking mechanisms,~~the first quarter of 2015, as compared to the same period in 2014, driven by a $1.7 million reduction in tracked costs, which have no earnings impact, ~~(tracked costs), and costs~~ that are recovered through base electric distribution rates (and therefore impact earnings). Operations and Maintenance increased in the first half of 2014, as compared to the first half of 2013, driven by a $2.5 million increase in costs that impact earnings (primarilywas primarily attributable to ~~an increase~~lower employee-related costs, including benefit costs, and a $1.1 million reduction in ~~workers' compensation claims of $1.9 million~~non-tracked costs, which was primarily attributable to lower uncollectible expense and ~~higher bad debt expense of $0.8 million). Partially offsetting this increase was a decrease in costs that have no earnings impact of $0.3 million.~~lower vegetation management costs.

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

48

Amortization of ~~Rate Reduction Bonds~~Regulatory Assets, Net~~decreased in~~,reflects the ~~first half~~absence of the refund of the Phase I DOE proceeds to customers in 2014 as ~~compared~~well as other energy and energy related costs and amortizations that can fluctuate period to ~~the first half~~period based on timing of ~~2013, due~~costs incurred and related rate changes to ~~the maturity of the RRBs in June 2013.~~

~~Energy Efficiency Programs~~~~increased in the first half of 2014, as compared to the first half of 2013, due primarily to an increase~~recover these costs. Fluctuations in energy ~~efficiency costs in accordance with the three-year program guidelines established by the DPU. All~~and energy related costs are ~~fully~~ recovered ~~through DPU-approved tracking mechanisms~~from customers in rates and ~~therefore do not~~have no impact on earnings.

Taxes Other Than Income Taxes increased in the first ~~half~~quarter of ~~2014,~~2015, as compared to the ~~first half of 2013,~~same period in 2014, due primarily to an increase in property taxes as a result of ~~both~~ an increase in utility plant ~~balances and property tax rates.~~balances.

~~Income Tax~~Interest Expense

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

2013

Decrease

Percent

Income Tax Expense
$
16.1

$
21.8

$
(5.7)

(26.1)
%

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

58

~~EARNINGS SUMMARY~~

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

2013

Decrease

Percent

Net Income
$
25.1

$
35.0

$
(9.9)

(28.3)
%

~~In the first half of 2014, WMECO's earnings decreased,~~2015, as compared to the same period in ~~2013,~~2014, due primarily to the ~~establishment~~absence of a ~~$5.5~~2014 wholesale billing adjustment.

Income Tax Expense decreased in the first quarter of 2015, as compared to the same period in 2014, due primarily to lower pre-tax earnings ($2.6 million).

EARNINGS SUMMARY

WMECO's earnings decreased $4.9 million in the first quarter of 2015, as compared to the same period in 2014, due primarily to the $2.5 million after-tax reserve related to the ~~June 2014~~March 2015 FERC ROE ~~orders, an~~order and a decrease in revenues and increase in ~~workers' compensation claims, and higher depreciation and property tax expense.~~interest expense resulting from the absence of a 2014 wholesale billing adjustment. Partially offsetting these unfavorable earnings impacts ~~were an increase in generation earnings and~~was a decrease in ~~other interest expense.~~operations and maintenance expenses primarily attributable to lower uncollectible expense and lower vegetation management costs.

LIQUIDITY

WMECO had cash flows used in operating activities of $1.4 million in the first quarter of 2015, compared with cash flows provided by operating activities of ~~$96.6~~$46.3 million in the first ~~half~~quarter of ~~2014, compared with $119.3 million in the first half of 2013.~~2014. The decrease in operating cash flows was due primarily to the timing of collections and payments related to our working capital items, including accounts receivable. Accounts receivable increased due primarily to an increase in basic service rates effective January 1, 2015. In addition, the operating cash flows decrease was due to the timing of regulatory recoveries, resulting from the increase in purchased power costs. Partially offsetting these unfavorable cash flow impacts were income tax refunds of $3.7 million in the first quarter of 2015, compared with income tax payments of ~~$16.9~~$14.1 million in the first ~~half of 2014, compared with income tax refunds of $32.4 million in the first half of 2013 and the absence of costs recovered in rates related to the RRBs that were fully amortized in the second~~ quarter of 2013, partially offset by the receipt of $18.1 million in DOE Phase II Damages proceeds received on June 1, 2014 from the Yankee Companies associated with the spent nuclear fuel litigation and an increase in regulatory overrecoveries.

2014.

5949

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~~Eversource'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, natural 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.

IfOur Regulated companies are subject to credit risk from certain long-term or high-volume supply contracts with energy marketing companies. Our Regulated companies manage the ~~respective unsecured debt ratings~~credit risk with these counterparties in accordance with established credit risk practices and monitor contracting risks, including credit risk. As of ~~NU or its subsidiaries were reduced~~March 31, 2015, our Regulated companies held collateral (cash and letters of credit) from counterparties related to ~~below investment grade by either Moody's or S&P, certain~~our standard service contracts of ~~NU's contracts would require additional collateral in the form~~approximately $9 million. As of March 31, 2015, Eversource had cash posted of approximately $11 million with ISO-NE related to ~~be provided to counterparties and independent system operators. NU would have been and remains able to provide that collateral.~~

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

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~~Eversource's 2014 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~~Eversource 2014 Form 10-K.

ITEM 4.
CONTROLS AND PROCEDURES

Management, on behalf of ~~NU,~~Eversource, CL&P, NSTAR Electric, PSNH and WMECO, evaluated the design and operation of the disclosure controls and procedures as of ~~June 30, 2014~~March 31, 2015 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~~officer 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~~officer and principal financial officer have concluded, based on their review, that the disclosure controls and procedures of ~~NU,~~Eversource, 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~~officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosures.

There have been no changes in internal controls over financial reporting for ~~NU,~~Eversource, CL&P, NSTAR Electric, PSNH and WMECO during the quarter ended ~~June 30, 2014~~March 31, 2015 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

6050

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~~2014 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~~2014 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~~2014 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~~2014 Form 10-K.

ITEM 2.
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

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

Period

Total Number
of Shares
Purchased

Average
Price
Paid per
Share
Total Number of
Shares Purchased
as Part of Publicly
Announced Plans or
Programs
Approximate Dollar
Value of Shares that
May Yet Be Purchased
Under the Plans and
Programs (at month end)

April 1 – April 30, 2014

-

$
-
-
-

May 1 – May 31, 2014

-

-
-
-

June 1 – June 30, 2014

208,608

46.93
-
-

Total

208,608

$
46.93
-
-
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)
January 1 – January 31, 2015

-

$
-
-
-
February 1 – February 28, 2015

51,915

56.45
-
-
March 1 – March 31, 2015

-

-
-
-
Total

51,915

$
56.45
-
-

6151

ITEM 6.
EXHIBITS

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

~~Exhibit No.~~
~~Description~~
~~Listing of Exhibits (NU)~~
12
~~Ratio of Earnings to Fixed Charges~~
31
Certification of Thomas J. May, Chairman, President and Chief Executive Officer of NU, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
~~31.1~~
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of NU, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
32
Certification of Thomas J. May, Chairman, President and Chief Executive Officer of NU, and James J. Judge, Executive Vice President and Chief Financial Officer of NU, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
~~Listing of Exhibits (CL&P)~~
*4.1
Supplemental Indenture (2014 Series A Bond) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of April 1, 2014 (Exhibit 4.1, CL&P Current Report on Form 8-K filed April 29, 2014, File No. 000-00404)
12
~~Ratio of Earnings to Fixed Charges~~
31
Certification of Leon J. Olivier, Chief Executive Officer of CL&P, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
~~31.1~~
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of CL&P, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
32
Certification of Leon J. Olivier, Chief Executive Officer of CL&P, and James J. Judge, Executive Vice President and Chief Financial Officer of CL&P, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
~~Listing of Exhibits (NSTAR Electric)~~
12
~~Ratio of Earnings to Fixed Charges~~
31
Certification of Leon J. Olivier, Chief Executive Officer of NSTAR Electric, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
~~31.1~~
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of NSTAR Electric, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
32
Certification of Leon J. Olivier, Chief Executive Officer of NSTAR Electric, and James J. Judge, Executive Vice President and Chief Financial Officer of NSTAR Electric, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014

62

Exhibit No.
~~Listing of Exhibits (PSNH)~~
Description
12
~~Ratio of Earnings to Fixed Charges~~
31
Certification of Leon J. Olivier, Chief Executive Officer of PSNH, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
~~31.1~~
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of PSNH, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
32
Certification of Leon J. Olivier, Chief Executive Officer of PSNH, and James J. Judge, Executive Vice President and Chief Financial Officer of PSNH, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
~~Listing of Exhibits (WMECO)~~
12
~~Ratio of Earnings to Fixed Charges~~
31
Certification of Leon J. Olivier, Chief Executive Officer of WMECO, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
~~31.1~~
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of WMECO, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014
32
Certification of Leon J. Olivier, Chief Executive Officer of WMECO, and James J. Judge, Executive Vice President and Chief Financial Officer of WMECO, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 1, 2014

Listing of Exhibits ~~(NU,~~(Eversource)

3.1
Declaration of Trust of Eversource Energy, as amended through April 29, 2015

* 4
Sixth Supplemental Indenture between Northeast Utilities, now known as Eversource Energy, and The Bank of New York Trust Company N.A., as Trustee, dated as of January 1, 2015, relating to $150 million of Senior Notes, Series G, due 2018 and $300 million of Senior Notes, Series H, due 2025 (Exhibit 4.1, NU Current Report on Form 8-K filed January 21, 2015, File No. 001-05324)

12
Ratio of Earnings to Fixed Charges

31
Certification of Thomas J. May, Chairman, President and Chief Executive Officer of Eversource Energy, 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 May 6, 2015

31.1
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of Eversource Energy, 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 May 6, 2015

32
Certification of Thomas J. May, Chairman, President and Chief Executive Officer of Eversource Energy, and James J. Judge, Executive Vice President and Chief Financial Officer of Eversource Energy, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 6, 2015

Listing of Exhibits (CL&P)

12
Ratio of Earnings to Fixed Charges

31
Certification of Thomas J. May, Chairman of The Connecticut Light and Power Company, 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 May 6, 2015

31.1
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power Company, 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 May 6, 2015

32
Certification of Thomas J. May, Chairman of The Connecticut Light and Power Company, and James J. Judge, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 6, 2015

Listing of Exhibits (NSTAR Electric Company)

12
Ratio of Earnings to Fixed Charges

31
Certification of Thomas J. May, Chairman of NSTAR Electric Company, 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 May 6, 2015

31.1
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of NSTAR Electric Company, 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 May 6, 2015

32
Certification of Thomas J. May, Chairman of NSTAR Electric Company, and James J. Judge, Executive Vice President and Chief Financial Officer of NSTAR Electric Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 6, 2015

52

Listing of Exhibits (PSNH)

12
Ratio of Earnings to Fixed Charges

31
Certification of Thomas J. May, Chairman of Public Service Company of New Hampshire, 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 May 6, 2015

31.1
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of Public Service Company of New Hampshire, 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 May 6, 2015

32
Certification of Thomas J. May, Chairman of Public Service Company of New Hampshire, and James J. Judge, Executive Vice President and Chief Financial Officer of Public Service Company of New Hampshire, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 6, 2015

Listing of Exhibits (WMECO)

12
Ratio of Earnings to Fixed Charges

31
Certification of Thomas J. May, Chairman of Western Massachusetts Electric Company, 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 May 6, 2015

31.1
Certification of James J. Judge, Executive Vice President and Chief Financial Officer of Western Massachusetts Electric Company, 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 May 6, 2015

32
Certification of Thomas J. May, Chairman of Western Massachusetts Electric Company, and James J. Judge, Executive Vice President and Chief Financial Officer of Western Massachusetts Electric Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 6, 2015

Listing of Exhibits (Eversource, 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

~~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

6353

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~~EVERSOURCE ENERGY

~~August 1, 2014~~May 6, 2015

By:
/s/
Jay S. Buth

Jay S. Buth

Vice President, Controller and Chief Accounting Officer

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.

THE CONNECTICUT LIGHT AND POWER COMPANY

~~August 1, 2014~~May 6, 2015

By:
/s/
Jay S. Buth

Jay S. Buth

Vice President, Controller and Chief Accounting Officer

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.

NSTAR ELECTRIC COMPANY

~~August 1, 2014~~May 6, 2015

By:
/s/
Jay S. Buth

Jay S. Buth

Vice President, Controller and Chief Accounting Officer

6454

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.

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

~~August 1, 2014~~May 6, 2015

By:
/s/
Jay S. Buth

Jay S. Buth

Vice President, Controller and Chief Accounting Officer

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.

WESTERN MASSACHUSETTS ELECTRIC COMPANY

~~August 1, 2014~~May 6, 2015

By:
/s/
Jay S. Buth

Jay S. Buth

Vice President, Controller and Chief Accounting Officer

6555


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

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

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

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


						Total Provision for Uncollectible Accounts				Uncollectible Hardship
(Millions of Dollars)	As of June 30, 2014		As of December 31, 2013		(Millions of Dollars)	As of March 31, 2015		As of December 31, 2014		As of March 31, 2015		As of December 31, 2014
NU	$	197.4	$	171.3
ES					ES	$	187.4	$	175.3	$	92.3	$	91.5
CL&P		91.8		82.0	CL&P		86.6		84.3		74.5		74.0
NSTAR Electric		44.4		41.7	NSTAR Electric		43.8		40.7		-		-
PSNH		9.2		7.4	PSNH		8.1		7.7		-		-
WMECO		12.9		10.0	WMECO		10.7		9.9		6.5		6.2


	For the Three Months Ended				For the Six Months Ended				For the Three Months Ended
(Millions of Dollars)	June 30, 2014		June 30, 2013		June 30, 2014		June 30, 2013		March 31, 2015		March 31, 2014
NU	$	35.2	$	33.0	$	79.6	$	71.4
ES									$	41.9	$	44.4
CL&P		30.9		29.8		66.5		61.8		33.0		35.6


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

(Millions of Dollars)		As of March 31, 2015		As of March 31, 2014
ES		$	110.4	$	108.5
CL&P			42.3		36.2
NSTAR Electric			21.9		28.0
PSNH			21.7		14.4
WMECO			8.3		14.4


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

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


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


		Pension and SERP				Pension and SERP					Pension and SERP
		For the Three Months Ended				For the Six Months Ended					For the Three Months Ended
		June 30, 2014		June 30, 2013		June 30, 2014		June 30, 2013			March 31, 2015		March 31, 2014
(Millions of Dollars)	(Millions of Dollars)	NU		NU		NU		NU		(Millions of Dollars)	ES⁽¹⁾		ES
Service Cost	Service Cost	$	19.1	$	24.6	$	41.5	$	51.1	Service Cost	$	23.2	$	22.3
Interest Cost	Interest Cost		56.3		51.9		113.0		103.5	Interest Cost		56.6		56.6
Expected Return on Plan Assets	Expected Return on Plan Assets		(77.7)		(68.6)		(155.4)		(139.0)	Expected Return on Plan Assets		(84.3)		(77.7)
Actuarial Loss	Actuarial Loss		31.7		52.6		64.7		105.5	Actuarial Loss		38.9		33.0
Prior Service Cost	Prior Service Cost		1.1		1.0		2.1		2.1	Prior Service Cost		0.9		1.1
Total Net Periodic Benefit Expense	Total Net Periodic Benefit Expense	$	30.5	$	61.5	$	65.9	$	123.2	Total Net Periodic Benefit Expense	$	35.3	$	35.3
Capitalized Pension Expense	Capitalized Pension Expense	$	8.7	$	19.9	$	18.4	$	36.6	Capitalized Pension Expense	$	9.6	$	9.7

		PBOP				PBOP					PBOP
		For the Three Months Ended				For the Six Months Ended					For the Three Months Ended
		June 30, 2014		June 30, 2013		June 30, 2014		June 30, 2013			March 31, 2015		March 31, 2014
(Millions of Dollars)	(Millions of Dollars)	NU		NU		NU		NU		(Millions of Dollars)	ES⁽¹⁾		ES
Service Cost	Service Cost	$	3.2	$	3.7	$	6.3	$	8.5	Service Cost	$	4.2	$	3.0
Interest Cost	Interest Cost		12.1		10.9		24.7		23.6	Interest Cost		11.9		12.6
Expected Return on Plan Assets	Expected Return on Plan Assets		(15.8)		(13.9)		(31.6)		(27.7)	Expected Return on Plan Assets		(16.8)		(15.7)
Actuarial Loss	Actuarial Loss		3.0		4.7		6.0		13.0	Actuarial Loss		1.8		3.0
Prior Service Credit	Prior Service Credit		(0.7)		(0.5)		(1.4)		(1.1)	Prior Service Credit		(0.1)		(0.6)
Total Net Periodic Benefit Expense	Total Net Periodic Benefit Expense	$	1.8	$	4.9	$	4.0	$	16.3	Total Net Periodic Benefit Expense	$	1.0	$	2.3
Capitalized PBOP Expense	Capitalized PBOP Expense	$	0.4	$	1.5	$	0.8	$	5.0	Capitalized PBOP Expense	$	0.2	$	0.4


		Pension and SERP																	Pension and SERP
		For the Three Months Ended June 30, 2014								For the Three Months Ended June 30, 2013									For the Three Months Ended March 31, 2015								For the Three Months Ended March 31, 2014
				NSTAR								NSTAR									NSTAR								NSTAR
(Millions of Dollars)	(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric⁽¹⁾		PSNH		WMECO		(Millions of Dollars)	CL&P		Electric		PSNH⁽¹⁾		WMECO		CL&P		Electric		PSNH		WMECO
Service Cost	Service Cost	$	5.0	$	3.0	$	2.3	$	0.8	$	6.3	$	7.3	$	3.2	$	1.2	Service Cost	$	6.0	$	3.8	$	2.9	$	1.1	$	5.2	$	4.6	$	2.8	$	1.0
Interest Cost	Interest Cost		12.4		10.3		5.8		2.5		12.1		14.7		5.9		2.5	Interest Cost		12.7		10.2		5.9		2.5		13.3		10.2		6.5		2.7
Expected Return on Plan Assets	Expected Return on Plan Assets		(18.7)		(15.7)		(9.3)		(4.4)		(18.4)		(20.2)		(9.2)		(4.4)	Expected Return on Plan Assets		(19.7)		(17.6)		(10.0)		(4.7)		(19.4)		(15.8)		(10.2)		(4.6)
Actuarial Loss	Actuarial Loss		8.2		5.9		2.8		1.7		13.9		14.6		5.4		2.9	Actuarial Loss		8.2		9.6		3.0		1.6		9.1		5.8		3.3		1.9
Prior Service Cost/(Credit)			0.5		-		0.1		0.1		0.5		(0.1)		0.1		0.1
Prior Service Cost																		Prior Service Cost		0.4		-		0.1		0.1		0.5		-		0.2		0.1
Total Net Periodic Benefit Expense	Total Net Periodic Benefit Expense	$	7.4	$	3.5	$	1.7	$	0.7	$	14.4	$	16.3	$	5.4	$	2.3	Total Net Periodic Benefit Expense	$	7.6	$	6.0	$	1.9	$	0.6	$	8.7	$	4.8	$	2.6	$	1.1
Intercompany Allocations	Intercompany Allocations	$	7.5	$	1.4	$	2.1	$	1.4	$	11.3	$	(2.2)	$	2.6	$	2.0	Intercompany Allocations	$	6.4	$	3.6	$	1.7	$	1.2	$	6.8	$	2.4	$	1.9	$	1.3
Capitalized Pension Expense	Capitalized Pension Expense	$	4.4	$	1.0	$	0.8	$	0.6	$	7.0	$	6.5	$	1.7	$	1.3	Capitalized Pension Expense	$	4.3	$	2.8	$	0.8	$	0.5	$	4.9	$	1.9	$	0.9	$	0.8

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


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


		Maximum Exposure
~~Subsidiary~~Company	Description	(in millions)				Expiration Dates

Various	Surety Bonds	$	~~67.0~~		~~2014 - 2016~~⁽¹⁾
	$
~~Various~~54.6	~~New England Hydro Companies~~' ~~Long-Term Debt~~		$	~~2.5~~		~~Unspecified~~2015 - 2016

~~NUSCO~~Eversource Service and ~~RRR~~Rocky River Realty Company	Lease Payments for Vehicles and Real Estate	$	~~16.0~~	13.8	2019 and 2024


		As of June 30, 2014				As of December 31, 2013					As of March, 31, 2015				As of December 31, 2014
		NU				NU					ES				ES
		Carrying		Fair		Carrying		Fair			Carrying		Fair		Carrying		Fair
(Millions of Dollars)	(Millions of Dollars)	Amount		Value		Amount		Value		(Millions of Dollars)	Amount		Value		Amount		Value
Preferred Stock Not Subject to Mandatory Redemption	Preferred Stock Not Subject to Mandatory Redemption	$	155.6	$	150.1	$	155.6	$	152.7	Preferred Stock Not Subject to Mandatory Redemption	$	155.6	$	155.1	$	155.6	$	153.6
Long-Term Debt	Long-Term Debt		8,542.7		9,008.4		8,310.2		8,443.1	Long-Term Debt		8,847.7		9,553.1		8,851.6		9,451.2


	Shares					Shares
			Authorized as of					Authorized as of
	Per Share		June 30, 2014 and	Issued as of		Per Share		March 31, 2015 and	Issued as of
	Par Value		December 31, 2013	June 30, 2014	December 31, 2013	Par Value		December 31, 2014	March 31, 2015	December 31, 2014
NU	$	5	380,000,000	333,327,485	333,113,492
ES						$	5	380,000,000	333,607,844	333,359,172
CL&P	$	10	24,500,000	6,035,205	6,035,205	$	10	24,500,000	6,035,205	6,035,205
NSTAR Electric	$	1	100,000,000	100	100	$	1	100,000,000	100	100
PSNH	$	1	100,000,000	301	301	$	1	100,000,000	301	301
WMECO	$	25	1,072,471	434,653	434,653	$	25	1,072,471	434,653	434,653


12. COMMON SHAREHOLDERS' EQUITY AND NONCONTROLLING INTERESTS

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

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


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

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


The following table summarizes NU's segmented total assets:

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


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


	For the Three Months Ended June 30,				For the Six Months Ended June 30,				For the Three Months Ended March 31,
(Millions of Dollars)	2014		2013		2014		2013
									2015				2014
(Millions of Dollars, Except Per Share Amounts)									Amount		Per Share		Amount		Per Share
Electric Distribution	$	83.4	$	91.2	$	195.6	$	190.6	$	130.6	$	0.41	$	112.2	$	0.35
Transmission		43.9		76.8		118.8		156.7		66.6		0.21		74.9		0.24
Natural Gas Distribution		2.0		1.2		54.1		44.5		55.6		0.18		52.1		0.16
Net Income - Regulated Companies	$	129.3	$	169.2	$	368.5	$	391.8	$	252.8	$	0.80	$	239.2	$	0.75


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


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


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

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


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

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


(Millions of Dollars)	Increase/(Decrease)
Electric Distribution	$	138.6
Natural Gas Distribution		62.3
Transmission		0.9
Other and Eliminations		(17.9)
Total Purchased Power, Fuel and Transmission	$	183.9


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


(Millions of Dollars)	Increase/(Decrease)
Base Electric Distribution:
Resolution of basic service bad debt adder mechanism at NSTAR Electric	$	(24.2)
Increase in employee-related costs, including labor and benefits, as a result of the impact from winter weather and storms, as compared to the first quarter of 2014		10.5
Implementation of a new outage restoration program at CL&P		3.9
All other operations and maintenance		2.6
Total Base Electric Distribution		(7.2)
Total Base Natural Gas Distribution		3.6
Total Tracked costs (Transmission and Electric and Natural Gas Distribution)		(2.7)
Total Distribution and Transmission		(6.3)
Other and eliminations:
Integration costs		(2.5)
All other (including eliminations)		(9.5)
Total Operations and Maintenance	$	(18.3)


(Millions of Dollars)	Increase/(Decrease)
NSTAR Electric (primarily 2014 Comprehensive Settlement Agreement and deferred transition costs)	$	(21.3)
CL&P (primarily storm cost recovery and energy supply and energy-related costs)		18.4
PSNH (primarily default energy service charge)		2.5
WMECO		3.5
Other		(0.4)
Total Amortization of Regulatory Assets, Net	$	2.7


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


(Millions of Dollars)	Increase/(Decrease)
Purchased Power Costs	$	71.3
Transmission Costs		(18.2)
Other		(0.9)
Total Purchased Power and Transmission	$	52.2


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

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


(Millions of Dollars)	~~Six Months Ended~~ Increase/(Decrease)
~~Basic Service~~Purchased Power Costs	$	~~115.4~~99.0
Transmission Costs		~~26.4~~ (16.1)
~~Purchased Power Costs~~Other		~~20.1~~ (0.1)
~~Deferred Fuel Costs~~		~~(3.8)~~
Total Purchased Power and Transmission	$	~~158.1~~82.8


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