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

For the Three Months Ended March 31,
(Thousands of Dollars, Except Share Information)
2013

2012

Operating Revenues
$
1,995,023

$
1,099,623

Operating Expenses:

Purchased Power, Fuel and Transmission

747,809

395,344

Operations and Maintenance

346,092

261,963

Depreciation

154,977

80,839

Amortization of Regulatory Assets, Net

54,049

5,426

Amortization of Rate Reduction Bonds

34,499

18,347

Energy Efficiency Programs

105,771

37,273

Taxes Other Than Income Taxes

132,881

86,038

Total Operating Expenses

1,576,078

885,230
Operating Income

418,945

214,393

Interest Expense:

Interest on Long-Term Debt

85,295

59,968

Interest on Rate Reduction Bonds

611

1,431

Other Interest

(9,651)

5,048

Interest Expense

76,255

66,447
Other Income, Net

7,765

8,773
Income Before Income Tax Expense

350,455

156,719
Income Tax Expense

120,487

55,964
Net Income

229,968

100,755
Net Income Attributable to Noncontrolling Interests

1,879

1,493
Net Income Attributable to Controlling Interest
$
228,089

$
99,262

Basic and Diluted Earnings Per Common Share
$
0.72

$
0.56

Dividends Declared Per Common Share
$
0.37

$
0.29

Weighted Average Common Shares Outstanding:

Basic

315,129,782

178,055,716

Diluted

316,002,538

178,437,453

��

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

Net Income
$
229,968

$
100,755
Other Comprehensive Income, Net of Tax:

Qualified Cash Flow Hedging Instruments

516

423

Changes in Unrealized Gains/(Losses) on Other Securities

(181)

34

Changes in Funded Status of Pension, SERP and PBOP

Benefit Plans

1,621

1,407
Other Comprehensive Income, Net of Tax

1,956

1,864
Comprehensive Income Attributable to Noncontrolling Interests

(1,879)

(1,493)
Comprehensive Income Attributable to Controlling Interest
$
230,045

$
101,126

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 Three Months Ended March 31,
(Thousands of Dollars)
2013

2012

Operating Activities:

Net Income
$
229,968

$
100,755

Adjustments to Reconcile Net Income to Net Cash Flows

Provided by Operating Activities:

Depreciation

154,977

80,839

Deferred Income Taxes

168,938

52,474

Pension, SERP and PBOP Expense

53,102

42,268

Pension and PBOP Contributions

(47,048)

(98,910)

Regulatory Over/(Under) Recoveries, Net

39,218

(27,569)

Amortization of Regulatory Assets, Net

54,049

5,426

Amortization of Rate Reduction Bonds

34,499

18,347

Proceeds from DOE Damages Claim

77,936

-

Other

(51,106)

(5,484)

Changes in Current Assets and Liabilities:

Receivables and Unbilled Revenues, Net

(129,431)

29,276

Fuel, Materials and Supplies

28,487

30,108

Taxes Receivable/Accrued, Net

(21,295)

11,758

Accounts Payable

(86,916)

(190,232)

Other Current Assets and Liabilities, Net

(32,235)

(40,240)
Net Cash Flows Provided by Operating Activities

473,143

8,816

Investing Activities:

Investments in Property, Plant and Equipment

(388,950)

(304,294)

Proceeds from Sales of Marketable Securities

98,070

40,947

Purchases of Marketable Securities

(184,030)

(41,570)

Other Investing Activities

27,997

2,448
Net Cash Flows Used in Investing Activities

(446,913)

(302,469)

Financing Activities:

Cash Dividends on Common Shares

(116,431)

(52,104)

Cash Dividends on Preferred Stock

(1,879)

(1,390)

(Decrease)/Increase in Short-Term Debt

(228,000)

343,000

Issuance of Long-Term Debt

400,000

300,000

Retirements of Rate Reduction Bonds

(62,529)

(17,903)

Other Financing Activities

(2,322)

(1,130)
Net Cash Flows (Used in)/Provided by Financing Activities

(11,161)

570,473
Net Increase in Cash and Cash Equivalents

15,069

276,820
Cash and Cash Equivalents - Beginning of Period

45,748

6,559
Cash and Cash Equivalents - End of Period
$
60,817

$
283,379

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

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

March 31,

December 31,
(Thousands of Dollars)
2013

2012

ASSETS

Current Assets:

Cash
$
8,307

$
1

Receivables, Net

318,111

284,787

Accounts Receivable from Affiliated Companies

2,942

6,641

Unbilled Revenues

80,590

85,353

Regulatory Assets

172,883

185,858

Materials and Supplies

63,035

64,603

Prepayments and Other Current Assets

47,906

26,413
Total Current Assets

693,774

653,656

Property, Plant and Equipment, Net

6,184,628

6,152,959

Deferred Debits and Other Assets:

Regulatory Assets

2,141,137

2,158,363

Derivative Assets

94,970

90,612

Other Long-Term Assets

87,368

86,498
Total Deferred Debits and Other Assets

2,323,475

2,335,473

Total Assets
$
9,201,877

$
9,142,088

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

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

March 31,

December 31,
(Thousands of Dollars)
2013

2012

LIABILITIES AND CAPITALIZATION

Current Liabilities:

Notes Payable to Affiliated Companies
$
210,400

$
99,296

Long-Term Debt - Current Portion

125,000

125,000

Accounts Payable

196,526

262,857

Accounts Payable to Affiliated Companies

31,968

52,326

Obligations to Third Party Suppliers

67,833

67,344

Accrued Taxes

53,383

60,109

Regulatory Liabilities

42,324

32,119

Derivative Liabilities

95,573

96,931

Other Current Liabilities

102,094

125,662
Total Current Liabilities

925,101

921,644

Deferred Credits and Other Liabilities:

Accumulated Deferred Income Taxes

1,401,609

1,336,105

Regulatory Liabilities

110,688

124,319

Derivative Liabilities

826,023

865,571

Accrued Pension, SERP and PBOP

304,549

304,696

Other Long-Term Liabilities

192,624

197,434
Total Deferred Credits and Other Liabilities

2,835,493

2,828,125

Capitalization:

Long-Term Debt

2,740,614

2,737,790

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

1,640,566

1,640,149

Retained Earnings

885,246

839,628

Accumulated Other Comprehensive Loss

(1,695)

(1,800)

Common Stockholder's Equity

2,584,469

2,538,329
Total Capitalization

5,441,283

5,392,319

Total Liabilities and Capitalization
$
9,201,877

$
9,142,088

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

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

For the Three Months Ended March 31,
(Thousands of Dollars)
2013

2012

Operating Revenues
$
624,097

$
591,965

Operating Expenses:

Purchased Power and Transmission

229,259

220,891

Operations and Maintenance

108,895

132,902

Depreciation

42,448

41,070

Amortization of Regulatory Assets, Net

10,787

7,994

Energy Efficiency Programs

22,813

21,973

Taxes Other Than Income Taxes

60,192

55,270

Total Operating Expenses

474,394

480,100
Operating Income

149,703

111,865

Interest Expense:

Interest on Long-Term Debt

32,635

31,521

Other Interest

(2,941)

1,987

Interest Expense

29,694

33,508
Other Income, Net

4,187

5,300
Income Before Income Tax Expense

124,196

83,657
Income Tax Expense

39,188

29,672
Net Income
$
85,008

$
53,985

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

Net Income
$
85,008

$
53,985
Other Comprehensive Income, Net of Tax:

Qualified Cash Flow Hedging Instruments

111

111

Changes in Unrealized Gains/(Losses) on Other

Securities

(6)

1
Other Comprehensive Income, Net of Tax

105

112
Comprehensive Income
$
85,113

$
54,097

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

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

For the Three Months Ended March 31,
(Thousands of Dollars)
2013

2012

Operating Activities:

Net Income
$
85,008

$
53,985

Adjustments to Reconcile Net Income to Net Cash Flows

Provided by/(Used in) Operating Activities:

Depreciation

42,448

41,070

Deferred Income Taxes

65,475

32,460

Pension, SERP and PBOP Expense, Net of PBOP Contributions

8,183

9,095

Regulatory Underrecoveries, Net

(15,835)

(39,407)

Amortization of Regulatory Assets, Net

10,787

7,994

Other

3,653

(6,399)

Changes in Current Assets and Liabilities:

Receivables and Unbilled Revenues, Net

(32,041)

28,685

Taxes Receivable/Accrued, Net

(12,777)

16,551

Accounts Payable

(106,140)

(146,676)

Other Current Assets and Liabilities, Net

(22,340)

(44,484)
Net Cash Flows Provided by/(Used in) Operating Activities

26,421

(47,126)

Investing Activities:

Investments in Property, Plant and Equipment

(89,360)

(108,842)

Other Investing Activities

447

1,139
Net Cash Flows Used in Investing Activities

(88,913)

(107,703)

Financing Activities:

Cash Dividends on Common Stock

(38,000)

(33,495)

Cash Dividends on Preferred Stock

(1,390)

(1,390)

Issuance of Long Term Debt

400,000

-

(Decrease)/Increase in Short-Term Debt

(283,700)

194,750

Other Financing Activities

(6,112)

(1,200)
Net Cash Flows Provided by Financing Activities

70,798

158,665
Net Increase in Cash

8,306

3,836
Cash - Beginning of Period

1

1
Cash - End of Period
$
8,307

$
3,837

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

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

March 31,

December 31,
(Thousands of Dollars)
2013

2012

ASSETS

Current Assets:

Cash and Cash Equivalents
$
17,109

$
13,695

Receivables, Net

233,438

202,025

Accounts Receivable from Affiliated Companies

303,699

160,176

Unbilled Revenues

35,895

41,377

Regulatory Assets

309,559

347,081

Prepayments and Other Current Assets

42,425

28,086
Total Current Assets

942,125

792,440

Property, Plant and Equipment, Net

4,788,158

4,735,297

Deferred Debits and Other Assets:

Regulatory Assets

1,489,317

1,444,870

Other Long-Term Assets

57,036

87,382
Total Deferred Debits and Other Assets

1,546,353

1,532,252

Total Assets
$
7,276,636

$
7,059,989

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

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

March 31,

December 31,
(Thousands of Dollars)
2013

2012

LIABILITIES AND CAPITALIZATION

Current Liabilities:

Notes Payable
$
308,000

$
276,000

Long-Term Debt - Current Portion

1,650

1,650

Accounts Payable

205,738

168,611

Accounts Payable to Affiliated Companies

353,037

247,061

Accumulated Deferred Income Taxes - Current Portion

84,096

104,668

Regulatory Liabilities

67,277

47,539

Other Current Liabilities

148,360

144,433
Total Current Liabilities

1,168,158

989,962

Rate Reduction Bonds

-

43,493

Deferred Credits and Other Liabilities:

Accumulated Deferred Income Taxes

1,365,951

1,321,026

Regulatory Liabilities

248,376

244,224

Accrued Pension

362,432

360,932

Payable to Affiliated Companies

65,668

70,221

Other Long-Term Liabilities

171,439

183,190
Total Deferred Credits and Other Liabilities

2,213,866

2,179,593

Capitalization:

Long-Term Debt

1,600,950

1,600,911

Preferred Stock Not Subject to Mandatory Redemption

43,000

43,000

Common Stockholder's Equity:

Common Stock

-

-

Capital Surplus, Paid In

992,625

992,625

Retained Earnings

1,258,037

1,210,405

Common Stockholder's Equity

2,250,662

2,203,030
Total Capitalization

3,894,612

3,846,941

Total Liabilities and Capitalization
$
7,276,636

$
7,059,989

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

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

For the Three Months Ended March 31,
(Thousands of Dollars)
2013

2012

Operating Revenues
$
592,257

$
556,476

Operating Expenses:

Purchased Power and Transmission

214,053

219,010

Operations and Maintenance

92,301

148,180

Depreciation

45,441

42,529

Amortization of Regulatory Assets, Net

46,994

23,880

Amortization of Rate Reduction Bonds

15,054

22,581

Energy Efficiency Programs

51,703

46,904

Taxes Other Than Income Taxes

32,174

30,861

Total Operating Expenses

497,720

533,945
Operating Income

94,537

22,531

Interest Expense:

Interest on Long-Term Debt

19,592

22,288

Interest on Rate Reduction Bonds

399

1,326

Other Interest

(4,068)

(5,836)

Interest Expense

15,923

17,778
Other Income, Net

773

1,222
Income Before Income Tax Expense

79,387

5,975
Income Tax Expense

31,265

2,035
Net Income
$
48,122

$
3,940

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

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

For the Three Months Ended March 31,
(Thousands of Dollars)
2013

2012

Operating Activities:

Net Income
$
48,122

$
3,940

Adjustments to Reconcile Net Income to Net Cash Flows

Provided by Operating Activities:

Bad Debt Expense

5,523

21,618

Depreciation

45,441

42,529

Deferred Income Taxes

26,571

(19,446)

Pension and PBOP Expense, net of Pension and PBOP Contributions

6,420

16,997

Regulatory (Under)/Over Recoveries, Net

(2,951)

24,719

Amortization of Regulatory Assets, Net

46,994

23,880

Amortization of Rate Reduction Bonds

15,054

22,581

Other

(23,969)

(22,647)

Changes in Current Assets and Liabilities:

Receivables and Unbilled Revenues, Net

(174,978)

15,109

Materials and Supplies

(7,060)

(9,340)

Taxes Receivable/Accrued, Net

(22,501)

14,645

Accounts Payable

107,843

(72,303)

Other Current Assets and Liabilities, Net

18,916

34,223

Net Cash Flows Provided by Operating Activities

89,425

96,505

Investing Activities:

Investments in Property, Plant and Equipment

(107,573)

(92,870)

Decrease in Special Deposits

33,631

25,898

Other Investing Activities

(86)

375

Net Cash Flows Used in Investing Activities

(74,028)

(66,597)

Financing Activities:

Cash Dividends on Common Stock

-

(57,100)

Cash Dividends on Preferred Stock

(490)

(490)

Increase in Short-Term Debt

32,000

71,000

Retirements of Rate Reduction Bonds

(43,493)

(43,548)

Net Cash Flows Used in Financing Activities

(11,983)

(30,138)

Net Increase/(Decrease) in Cash and Cash Equivalents

3,414

(230)

Cash and Cash Equivalents - Beginning of Period

13,695

9,373

Cash and Cash Equivalents - End of Period
$
17,109

$
9,143

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

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

March 31,

December 31,
(Thousands of Dollars)
2013

2012

ASSETS

Current Assets:

Cash
$
3,376

$
2,493

Receivables, Net

86,225

87,164

Accounts Receivable from Affiliated Companies

7,568

723

Unbilled Revenues

39,062

39,982

Taxes Receivable

2,020

17,177

Fuel, Materials and Supplies

94,783

95,345

Regulatory Assets

62,184

62,882

Prepayments and Other Current Assets

8,127

22,205
Total Current Assets

303,345

327,971

Property, Plant and Equipment, Net

2,360,753

2,352,515

Deferred Debits and Other Assets:

Regulatory Assets

329,314

351,059

Other Long-Term Assets

82,284

83,052
Total Deferred Debits and Other Assets

411,598

434,111

Total Assets
$
3,075,696

$
3,114,597

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

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

March 31,

December 31,
(Thousands of Dollars)
2013

2012

LIABILITIES AND CAPITALIZATION

Current Liabilities:

Notes Payable to Affiliated Companies
$
53,400

$
63,300

Long-Term Debt - Current Portion

108,985

-

Accounts Payable

64,619

62,864

Accounts Payable to Affiliated Companies

12,624

21,337

Accrued Interest

13,840

9,317

Regulatory Liabilities

18,132

23,002

Renewable Portfolio Standards Compliance Obligations

21,946

17,383

Other Current Liabilities

43,941

41,633
Total Current Liabilities

337,487

238,836

Rate Reduction Bonds

14,974

29,294

Deferred Credits and Other Liabilities:

Accumulated Deferred Income Taxes

449,979

441,577

Regulatory Liabilities

52,473

52,418

Accrued Pension, SERP and PBOP

186,836

220,129

Other Long-Term Liabilities

45,972

47,896
Total Deferred Credits and Other Liabilities

735,260

762,020

Capitalization:

Long-Term Debt

888,999

997,932

Common Stockholder's Equity:

Common Stock

-

-

Capital Surplus, Paid In

701,241

701,052

Retained Earnings

407,113

395,118

Accumulated Other Comprehensive Loss

(9,378)

(9,655)

Common Stockholder's Equity

1,098,976

1,086,515
Total Capitalization

1,987,975

2,084,447

Total Liabilities and Capitalization
$
3,075,696

$
3,114,597

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

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

For the Three Months Ended March 31,
(Thousands of Dollars)
2013

2012

Operating Revenues
$
273,829

$
242,997

Operating Expenses:

Purchased Power, Fuel and Transmission

101,024

81,049

Operations and Maintenance

59,729

64,979

Depreciation

22,568

21,208

Amortization of Regulatory Liabilities, Net

(3,051)

(2,622)

Amortization of Rate Reduction Bonds

14,756

13,930

Energy Efficiency Programs

3,669

3,581

Taxes Other Than Income Taxes

17,016

15,486

Total Operating Expenses

215,711

197,611
Operating Income

58,118

45,386

Interest Expense:

Interest on Long-Term Debt

11,796

11,563

Interest on Rate Reduction Bonds

85

1,016

Other Interest

287

234

Interest Expense

12,168

12,813
Other Income, Net

1,030

2,042
Income Before Income Tax Expense

46,980

34,615
Income Tax Expense

17,984

13,353
Net Income
$
28,996

$
21,262

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

Net Income
$
28,996

$
21,262
Other Comprehensive Income, Net of Tax:

Qualified Cash Flow Hedging Instruments

291

290

Changes in Unrealized Gains/(Losses) on Other Securities

(11)

2

Changes in Funded Status of Pension, SERP and PBOP

Benefit Plans

(3)

-
Other Comprehensive Income, Net of Tax

277

292
Comprehensive Income
$
29,273

$
21,554

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

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

For the Three Months Ended March 31,
(Thousands of Dollars)
2013

2012

Operating Activities:

Net Income
$
28,996

$
21,262

Adjustments to Reconcile Net Income to Net Cash Flows

Provided by Operating Activities:

Depreciation

22,568

21,208

Deferred Income Taxes

10,143

8,908

Pension, SERP and PBOP Expense

8,022

7,032

Pension and PBOP Contributions

(35,146)

(89,012)

Regulatory (Under)/Over Recoveries, Net

(799)

911

Amortization of Regulatory Liabilities, Net

(3,051)

(2,622)

Amortization of Rate Reduction Bonds

14,756

13,930

Other

(1,505)

9,569

Changes in Current Assets and Liabilities:

Receivables and Unbilled Revenues, Net

(13,889)

2,480

Fuel, Materials and Supplies

562

9,361

Taxes Receivable/Accrued, Net

23,137

10,138

Accounts Payable

31,257

(16,073)

Other Current Assets and Liabilities, Net

22,152

18,869
Net Cash Flows Provided by Operating Activities

107,203

15,961

Investing Activities:

Investments in Property, Plant and Equipment

(64,956)

(67,059)

Decrease in NU Money Pool Lending

-

55,900

Other Investing Activities

(17)

963
Net Cash Flows Used in Investing Activities

(64,973)

(10,196)

Financing Activities:

Cash Dividends on Common Stock

(17,000)

(42,891)

(Decrease)/Increase in Short-Term Debt

(9,900)

52,900

Retirements of Rate Reduction Bonds

(14,320)

(13,463)

Other Financing Activities

(127)

(116)
Net Cash Flows Used in Financing Activities

(41,347)

(3,570)
Net Increase in Cash

883

2,195
Cash - Beginning of Period

2,493

56
Cash - End of Period
$
3,376

$
2,251

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

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

March 31,

December 31,
(Thousands of Dollars)
2013

2012

ASSETS

Current Assets:

Cash
$
1,768

$
1

Receivables, Net

48,113

47,297

Accounts Receivable from Affiliated Companies

154

164

Unbilled Revenues

16,071

16,192

Taxes Receivable

3

15,513

Regulatory Assets

43,534

42,370

Marketable Securities

30,588

27,352

Prepayments and Other Current Assets

7,571

7,963
Total Current Assets

147,802

156,852

Property, Plant and Equipment, Net

1,305,743

1,290,498

Deferred Debits and Other Assets:

Regulatory Assets

207,901

221,752

Marketable Securities

27,169

30,342

Other Long-Term Assets

24,018

23,625
Total Deferred Debits and Other Assets

259,088

275,719

Total Assets
$
1,712,633

$
1,723,069

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

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

March 31,

December 31,
(Thousands of Dollars)
2013

2012

LIABILITIES AND CAPITALIZATION

Current Liabilities:

Notes Payable to Affiliated Companies
$
43,400

$
31,900

Long-Term Debt - Current Portion

55,000

55,000

Accounts Payable

44,303

68,141

Accounts Payable to Affiliated Companies

3,061

7,103

Accrued Interest

1,918

8,304

Regulatory Liabilities

15,638

21,037

Other Current Liabilities

32,756

24,909
Total Current Liabilities

196,076

216,394

Rate Reduction Bonds

4,636

9,352

Deferred Credits and Other Liabilities:

Accumulated Deferred Income Taxes

316,727

303,111

Regulatory Liabilities

9,736

9,686

Accrued Pension, SERP and PBOP

35,431

36,099

Other Long-Term Liabilities

33,203

40,148
Total Deferred Credits and Other Liabilities

395,097

389,044

Capitalization:

Long-Term Debt

550,057

550,270

Common Stockholder's Equity:

Common Stock

10,866

10,866

Capital Surplus, Paid In

390,485

390,412

Retained Earnings

169,179

160,577

Accumulated Other Comprehensive Loss

(3,763)

(3,846)

Common Stockholder's Equity

566,767

558,009
Total Capitalization

1,116,824

1,108,279

Total Liabilities and Capitalization
$
1,712,633

$
1,723,069

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

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

For the Three Months Ended March 31,
(Thousands of Dollars)
2013

2012

Operating Revenues
$
124,953

$
114,025

Operating Expenses:

Purchased Power and Transmission

40,044

40,554

Operations and Maintenance

20,928

22,601

Depreciation

8,970

7,697

Amortization of Regulatory Assets/(Liabilities), Net

129

(343)

Amortization of Rate Reduction Bonds

4,689

4,418

Energy Efficiency Programs

8,315

5,556

Taxes Other Than Income Taxes

6,288

4,882

Total Operating Expenses

89,363

85,365
Operating Income

35,590

28,660

Interest Expense:

Interest on Long-Term Debt

5,955

5,766

Interest on Rate Reduction Bonds

127

415

Other Interest

211

214

Interest Expense

6,293

6,395
Other Income, Net

1,004

1,092
Income Before Income Tax Expense

30,301

23,357
Income Tax Expense

11,698

9,171
Net Income
$
18,603

$
14,186

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

Net Income
$
18,603

$
14,186
Other Comprehensive Income, Net of Tax:

Qualified Cash Flow Hedging Instruments

85

85

Changes in Unrealized Gains/(Losses) on Other Securities

(2)

-
Other Comprehensive Income, Net of Tax

83

85
Comprehensive Income
$
18,686

$
14,271

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

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

For the Three Months Ended March 31,
(Thousands of Dollars)
2013

2012

Operating Activities:

Net Income
$
18,603

$
14,186

Adjustments to Reconcile Net Income to Net Cash Flows

Provided by Operating Activities:

Depreciation

8,970

7,697

Deferred Income Taxes

16,828

9,198

Pension, SERP and PBOP Expense, Net of PBOP Contributions

1,246

1,766

Regulatory Underrecoveries, Net

(2,357)

(1,778)

Amortization of Regulatory Assets/(Liabilities), Net

129

(343)

Amortization of Rate Reduction Bonds

4,689

4,418

Other

(2,545)

(1,071)

Changes in Current Assets and Liabilities:

Receivables and Unbilled Revenues, Net

(4,907)

(2,274)

Taxes Receivable/Accrued, Net

21,600

1,051

Accounts Payable

17,667

(21,870)

Other Current Assets and Liabilities, Net

(8,931)

(5,885)
Net Cash Flows Provided by Operating Activities

70,992

5,095

Investing Activities:

Investments in Property, Plant and Equipment

(66,340)

(85,011)

Proceeds from Sales of Marketable Securities

21,035

31,579

Purchases of Marketable Securities

(21,191)

(31,680)

Decrease in NU Money Pool Lending

-

11,000

Other Investing Activities

500

(169)
Net Cash Flows Used in Investing Activities

(65,996)

(74,281)

Financing Activities:

Cash Dividends on Common Stock

(10,000)

(9,432)

Increase in Short-Term Debt

11,500

83,200

Retirement of Rate Reduction Bonds

(4,716)

(4,440)

Other Financing Activities

(13)

(17)
Net Cash Flows (Used in)/Provided by Financing Activities

(3,229)

69,311
Net Increase in Cash

1,767

125
Cash - Beginning of Period

1

1
Cash - End of Period
$
1,768

$
126

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

NORTHEAST UTILITIES AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31,			December 31,
(Thousands of Dollars)	2014			2013

LIABILITIES AND CAPITALIZATION

Current Liabilities:
Notes Payable	$	571,147		$	1,093,000
Long-Term Debt - Current Portion	530,533			533,346
Accounts Payable	711,594			742,251
Regulatory Liabilities	263,754			204,278
Other Current Liabilities	713,116			702,776
Total Current Liabilities	2,790,144			3,275,651

Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes	4,209,969			4,029,026
Regulatory Liabilities	591,468			502,984
Derivative Liabilities	546,387			624,050
Accrued Pension, SERP and PBOP	890,019			896,844
Other Long-Term Liabilities	871,050			923,053
Total Deferred Credits and Other Liabilities	7,108,893			6,975,957

Capitalization:
Long-Term Debt	8,318,332			7,776,833

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

Equity:
Common Shareholders’ Equity:
Common Shares	1,666,580			1,665,351
Capital Surplus, Paid In	6,185,027			6,192,765
Retained Earnings	2,237,710			2,125,980
Accumulated Other Comprehensive Loss	(44,321		)	(46,031		)
Treasury Stock	(321,063		)	(326,537		)
Common Shareholders’ Equity	9,723,933			9,611,528
Total Capitalization	18,197,833			17,543,929

Total Liabilities and Capitalization	$	28,096,870		$	27,795,537

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

Table of Contents

Exit price premiums of 119 percent through 3226 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 ~~power~~energy or capacity prices in isolation would decrease or increase, respectively, the fair value of the derivative liability. Any increases in the risk premiums would increase the fair value of the derivative liabilities. Changes in these fair values are recorded as a regulatory asset or liability and would not impact net income.

Valuations using significant unobservable inputs: The following tables present changes for the three months ended March 31, ~~2013~~2014 and ~~2012~~2013 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. The fair value as of January 1, 2012 reflects a reclassification of remaining unregulated wholesale marketing sourcing contracts that had previously been presented as a portfolio along with the unregulated wholesale marketing sales contract as Level 3 under the highest and best use valuation premise. These contracts are now classified within Level 2 of the fair value hierarchy.


		For the Three Months Ended				For the Three Months Ended March 31,
		March 31, 2013		March 31, 2012		2014			2013
(Millions of Dollars)	(Millions of Dollars)	NU		NU		NU			NU
Derivatives, Net:	Derivatives, Net:
Fair Value as of Beginning of Period	Fair Value as of Beginning of Period	$	(878.6)	$	(962.2)	$	(635.2	)	$	(878.6	)
Transfer to Level 2			-		32.2
Net Realized/Unrealized Gains Included in:	Net Realized/Unrealized Gains Included in:
	Net Income⁽²⁾		5.7		8.0
	Regulatory Assets		26.2		6.0
Net Income (1)						—			5.7
Regulatory Assets and Liabilities						49.2			26.2
Settlements	Settlements		13.6		14.5	21.7			13.6
Fair Value as of End of Period	Fair Value as of End of Period	$	(833.1)	$	(901.5)	$	(564.3	)	$	(833.1	)

	For the Three Months Ended
	March 31, 2014						March 31, 2013
(Millions of Dollars)	CL&P			NSTAR Electric			CL&P			NSTAR Electric
Derivatives, Net:
Fair Value as of Beginning of Period	$	(630.6	)	$	(7.3	)	$	(866.2	)	$	(14.9	)
Net Realized/Unrealized Gains/(Losses) Included in Regulatory Assets and Liabilities	52.0			(0.1		)	24.3			0.7
Settlements	21.6			0.1			22.3			0.6
Fair Value as of End of Period	$	(557.0	)	$	(7.3	)	$	(819.6	)	$	(13.6	)

For the Three Months Ended

March 31, 2013

March 31, 2012
(Millions of Dollars)
CL&P

NSTAR Electric

WMECO

CL&P

NSTAR Electric⁽¹⁾

WMECO
Derivatives, Net:

Fair Value as of Beginning of Period
$
(866.2)

$
(14.9)

$
(3.0)

$
(931.6)

$
(3.4)

$
(7.3)
Net Realized/Unrealized Gains/(Losses)

Included in Regulatory Assets

24.3

0.7

1.2

10.9

(3.4)

(5.0)
Settlements

22.3

0.6

-

21.1

1.4

-
Fair Value as of End of Period
$
(819.6)

$
(13.6)

$
(1.8)

$
(899.6)

$
(5.4)

$
(12.3)

⁽¹⁾

~~NSTAR Electric amounts are not included in NU consolidated for the three months ended March 31, 2012.~~

⁽²⁾

The Net Income impact for the three months ended March 31, 2013 ~~and 2012 relates~~related to the unregulated wholesale marketing sales contract ~~and is~~that was offset by the gains/(losses) on the unregulated sourcing contracts classified as Level 2 in the fair value hierarchy, resulting in a total net ~~gains~~gain of $0.3 million ~~and net losses~~as of ~~$0.8 million, respectively.~~March 31, 2013.

MARKETABLE SECURITIES ~~(NU, WMECO)~~

NU maintains ~~a supplemental benefit trust~~trusts to fund certain ~~of NU’s~~ non-qualified executive ~~retirement benefit obligations~~benefits and WMECO maintains a spent nuclear fuel trust to fund WMECO’s prior period spent nuclear fuel liability, each of which hold marketable securities.

These trusts are not subject to regulatory oversight by state or federal agencies. ~~NU's marketable securities also include~~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 that are part of CYAPC and YAEC.~~plants.

~~The~~In accordance with applicable accounting guidance, the Company ~~elects~~elected to record mutual funds ~~purchased by the NU supplemental benefit trust~~designated as available-for-sale at fair ~~value. As such, any change~~value and certain other equity investments as trading securities, with the changes in fair ~~value~~values recorded in Other Income, Net on the statements of ~~these~~income. As of March 31, 2014, the mutual funds ~~is reflected in Net Income. These mutual funds,~~and equity investments were classified as Level 1 in the fair value hierarchy and totaled ~~$51.2~~$57.4 million and ~~$47~~$24 million, asrespectively. As of ~~March~~December 31, 2013, the mutual funds were classified as Level 1, and ~~December 31, 2012, respectively, and are included in current Marketable Securities.~~totaled $57.2 million. Net gains on ~~these securities of $4.2~~the mutual funds were $0.2 million and ~~$3.2~~$4.2 million for the three months ended March 31, 2014 and 2013, respectively, and ~~2012, respectively, were recorded in Other Income, Net~~net gains on the ~~consolidated statements of income.~~equity investments were $0.5 million for the three months ended March 31, 2014. Dividend income ~~is recorded when dividends are declared and~~ is recorded in Other Income, Net on the ~~consolidated~~ statements of ~~income.~~income when dividends are declared. All other marketable securities are accounted for as available-for-sale.

Available-for-Sale Securities: The following is a summary of ~~NU's~~NU’s and WMECO’s available-for-sale ~~securities held in the NU supplemental benefit trust, WMECO's spent nuclear fuel trust and CYAPC and YAEC's nuclear decommissioning trusts.~~securities. These securities are recorded at fair value and included in current and long-term Marketable Securities on the ~~consolidated~~ balance sheets.


		As of March 31, 2013								As of March 31, 2014
				Pre-Tax		Pre-Tax						Pre-Tax		Pre-Tax
		Amortized		Unrealized		Unrealized				Amortized		Unrealized		Unrealized
(Millions of Dollars)	(Millions of Dollars)	Cost		Gains⁽¹⁾		Losses⁽¹⁾		Fair Value		Cost		Gains(1)		Losses(1)			Fair Value
NU	NU
	Debt Securities⁽²⁾	$	355.3	$	10.0	$	(0.1)	$	365.2
	Equity Securities⁽²⁾		144.0		30.7		-		174.7
Debt Securities (2)										$	300.6	$	4.8	$	(0.7	)	$	304.7
Equity Securities (2)										163.3		65.6		—			228.9

WMECO	WMECO
Debt Securities										58.0		—		(0.1		)	57.9
	Debt Securities		57.7		0.1		-		57.8

		As of December 31, 2012
				Pre-Tax		Pre-Tax
		Amortized		Unrealized		Unrealized
(Millions of Dollars)		Cost		Gains⁽¹⁾		Losses⁽¹⁾		Fair Value
NU
	Debt Securities⁽²⁾	$	266.6	$	13.3	$	(0.1)	$	279.8
	Equity Securities⁽²⁾		145.5		20.0		-		165.5

WMECO
	Debt Securities		57.7		0.1		(0.1)		57.7

⁽¹⁾28

Table of Contents

	As of December 31, 2013
			Pre-Tax		Pre-Tax
	Amortized		Unrealized		Unrealized
(Millions of Dollars)	Cost		Gains(1)		Losses(1)			Fair Value
NU
Debt Securities (2)	$	299.2	$	2.5	$	(2.1	)	$	299.6
Equity Securities (2)	163.6		60.5		—			224.1

WMECO
Debt Securities	57.9		—		—			57.9

(1)Unrealized gains and losses on debt securities ~~for the NU supplemental benefit trust and~~held by WMECO ~~spent nuclear fuel trust~~ are recorded in ~~AOCI and~~ Other Long-Term Assets ~~respectively,~~ on the ~~consolidated~~ balance sheets.

⁽²⁾

~~NU's~~NU’s amounts include ~~CYAPC's~~CYAPC’s and ~~YAEC's~~YAEC’s marketable securities held in nuclear decommissioning trusts of ~~$434.9~~$435.9 million and ~~$340.4~~$424 million as of March 31, ~~2013~~2014 and December 31, ~~2012,~~2013, respectively, the majority of which are legally restricted and can only be used for the decommissioning of the nuclear power plants owned by these companies. In 2013, CYAPC and YAEC received cash from the DOE that was invested in the nuclear decommissioning trusts. For further information see Note 9B "Commitments and Contingencies - Deferred Contractual Obligations" to the consolidated financial statements. Unrealized gains and losses for the nuclear decommissioning trusts are offset in Other Long-Term Liabilities on the ~~consolidated~~ balance ~~sheets.~~sheets, with no impact on the statements of income. All of the equity securities accounted for as available-for-sale securities are held in these trusts.

Unrealized Losses and Other-than-Temporary Impairment: There have been no significant unrealized losses, other-than-temporary impairments or credit losses for ~~the~~ NU ~~supplemental benefit trust, the WMECO spent nuclear fuel trust, and in the trusts held by CYAPC and YAEC.Factors~~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 ~~the NU supplemental~~NU’s benefit trust, Other Long-Term Assets for ~~the~~ WMECO, ~~spent nuclear fuel trust,~~ and offset in Other Long-Term Liabilities for CYAPC and YAEC. NU utilizes the specific identification basis method for the NU ~~supplemental~~ benefit trust ~~securities~~ and the average cost basis method for the WMECO ~~spent nuclear fuel~~ 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 March 31, ~~2013,~~2014, the contractual maturities of available-for-sale debt securities are as follows:


		NU				WMECO				NU				WMECO
		Amortized				Amortized				Amortized				Amortized
(Millions of Dollars)	(Millions of Dollars)	Cost		Fair Value		Cost		Fair Value		Cost		Fair Value		Cost		Fair Value
Less than one year⁽¹⁾	Less than one year⁽¹⁾	$	150.7	$	150.8	$	30.4	$	30.6	$	54.5	$	54.4	$	19.2	$	19.2
One to five years	One to five years		62.2		63.5		18.7		18.5	73.3		73.9		33.2		33.2
Six to ten years	Six to ten years		51.2		53.4		4.1		4.1	68.1		69.4		1.6		1.6
Greater than ten years	Greater than ten years		91.2		97.5		4.5		4.6	104.7		107.0		4.0		3.9
Total Debt Securities	Total Debt Securities	$	355.3	$	365.2	$	57.7	$	57.8	$	300.6	$	304.7	$	58.0	$	57.9

⁽¹⁾

Amounts in the Less than one year NU category include securities in the CYAPC and YAEC nuclear decommissioning trusts, which are restricted and are classified in long-term Marketable Securities on the ~~consolidated~~ 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				NU				WMECO
			As of				As of				As of				As of
(Millions of Dollars)	(Millions of Dollars)		March 31, 2013		December 31, 2012		March 31, 2013		December 31, 2012		March 31, 2014		December 31, 2013		March 31, 2014		December 31, 2013
Level 1:	Level 1:
	Mutual Funds and Equities		$	225.9	$	212.5	$	-	$	-
	Money Market Funds			120.1		40.2		3.6		5.2
Mutual Funds and Equities											$	310.3	$	281.3	$	—	$	—
Money Market Funds											22.5		32.9		4.3		10.9
Total Level 1	Total Level 1		$	346.0	$	252.7	$	3.6	$	5.2	$	332.8	$	314.2	$	4.3	$	10.9
Level 2:	Level 2:
	U.S. Government Issued Debt Securities
		(Agency and Treasury)	$	78.5	$	69.9	$	18.2	$	18.7
	Corporate Debt Securities			41.1		33.0		11.7		7.0
	Asset-Backed Debt Securities			26.4		28.5		9.6		10.9
	Municipal Bonds			82.6		93.8		8.6		11.6
	Other Fixed Income Securities			16.5		14.4		6.1		4.3
U.S. Government Issued Debt Securities (Agency and Treasury)											$	56.7	$	61.4	$	—	$	6.8
Corporate Debt Securities											56.3		53.6		14.1		15.1
Asset-Backed Debt Securities											35.3		30.4		14.0		9.0
Municipal Bonds											109.6		105.5		12.3		11.2
Other Fixed Income Securities											24.3		15.8		13.2		4.9
Total Level 2	Total Level 2		$	245.1	$	239.6	$	54.2	$	52.5	$	282.2	$	266.7	$	53.6	$	47.0
Total Marketable Securities	Total Marketable Securities		$	591.1	$	492.3	$	57.8	$	57.7	$	615.0	$	580.9	$	57.9	$	57.9

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

6.29

Table of Contents

6.SHORT-TERM AND LONG-TERM DEBT

~~Limits:~~ The amount of short-term borrowings that may be incurred by CL&P, NSTAR Electric and WMECO is subject to periodic approval by the FERC. On November 30, 2011, the FERC granted authorization to allow CL&P and WMECO to incur total short-term borrowings up to a maximum of $450 million and $300 million, respectively, effective January 1, 2012 through December 31, 2013. On March 22, 2012, the FERC approved CL&P's application requesting to increase its total short-term borrowing capacity from a maximum of $450 million to a maximum of $600 million for the authorization period through December 31, 2013. On May 16, 2012, 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 23, 2012 through October 23, 2014. As a result of the NHPUC having jurisdiction over PSNH's short-term debt, PSNH is not currently required to obtain FERC approval for its short-term borrowings.

Credit Agreements and Commercial Paper Programs: NU parent, CL&P, PSNH, WMECO, NSTAR Gas and Yankee Gas are parties to a five-year $1.45 billion revolving credit facility due to expire on September 6, 2018. The revolving credit facility is to be used primarily to backstop the $1.45 billion commercial paper program at NU. The commercial paper program allows NU parent to issue commercial paper as a form of short-term debt. As of March 31, ~~2013~~2014 and December 31, ~~2012,~~2013, NU had ~~$979~~approximately $818.5 million and ~~$1.15~~$1.01 billion, respectively, in short-term borrowings outstanding under ~~its~~the NU parent commercial paper program, leaving ~~$171~~$631.5 million and $435.5 million of available borrowing capacity as of March 31, ~~2013.~~2014 and December 31, 2013, respectively. The weighted-average interest rate on these borrowings as of March 31, ~~2013~~2014 and December 31, ~~2012~~2013 was ~~0.35~~0.23 percent and ~~0.46~~0.24 percent, respectively, which is generally based on money market rates. As of March 31, ~~2013,~~2014, there were ~~inter-company~~intercompany loans ~~of $832 million~~ from NU ~~to its subsidiaries ($210.4~~of $351.6 million atto CL&P, ~~$53.4~~$39.9 million atto PSNH and ~~$43.4~~$37.4 million ~~at WMECO).~~to WMECO. As of December 31, ~~2012,~~2013, there were ~~inter-company~~intercompany loans ~~of $987.5 million~~ from NU ~~to its subsidiaries ($405.1~~of $287.3 million atto CL&P ~~$63.3~~and $86.5 million ~~at PSNH, and $31.9~~to PSNH.

NSTAR Electric has a five-year $450 million ~~at WMECO).~~revolving credit facility due to expire on September 6, 2018. This facility serves to backstop NSTAR Electric’s existing $450 million commercial paper program. As of March 31, ~~2013 and December 31, 2012,~~2014, NSTAR Electric had ~~$308~~no borrowings outstanding under its commercial paper program. As of December 31, 2013, NSTAR Electric had $103.5 million ~~and $276 million, respectively,~~ in short-term borrowings outstanding under its commercial paper program, leaving ~~$142~~$346.5 million ~~and $174 million, respectively,~~ of available borrowing capacity. The weighted-average interest rate on these borrowings as of ~~March~~December 31, 2013 ~~and December 31, 2012~~ was ~~0.28~~0.13 percent, ~~and 0.31 percent, respectively,~~ which is generally based on money market rates.

Amounts outstanding under the commercial paper ~~program~~programs are generally included in Notes Payable for NU and NSTAR Electric and classified in current liabilities on the ~~consolidated~~ balance sheets as ~~management anticipates that~~ all borrowings ~~under these credit facilities will be~~are outstanding for no more than 364 days at one time. Intercompany loans from NU to CL&P, PSNH and WMECO are included in Notes Payable to ~~Affiliated Companies~~NU Parent and classified in current liabilities on the ~~consolidated~~ balance sheets.

See the Long-Term Debt ~~Issuances:~~ portion of this Note for further information on the CL&P $250 million bond issuance and the Yankee Gas $100 million bond issuance and their impacts on the NU balance sheet as of March 31, 2014 and December 31, 2013, respectively.

Long-Term Debt: On January ~~15, 2013, CL&P~~2, 2014, Yankee Gas issued ~~$400~~$100 million of 4.82 percent Series AL First ~~and Refunding~~ Mortgage Bonds, ~~with a coupon rate of 2.5 percent and a maturity date of January 15, 2023.~~due to mature in 2044. The proceeds, net of issuance costs, were used to repay the $75 million 4.80 percent Series G First Mortgage Bonds that matured on January 1, 2014 and to pay $25 million in short-term borrowings outstanding under the CL&P credit agreement and the NU commercial paper program. Therefore, as of December 31, 2012, CL&P's credit agreement borrowings of $89 million and intercompany loans related to the commercial paper program of $305.8 million have beenborrowings. In accordance with applicable accounting guidance, these amounts were classified as Long-Term Debt on ~~the consolidated~~NU’s balance ~~sheet.~~sheet as of December 31, 2013.

On ~~May 1, 2013, PSNH redeemed at par approximately $109~~March 7, 2014, NSTAR Electric issued $300 million of ~~the 2001 Series C PCRBs that were~~4.40 percent debentures, due to mature in ~~2021~~2044. The proceeds, net of issuance costs, were used to repay the $300 million of 4.875 percent debentures that matured on April 15, 2014.

On April 24, 2014, CL&P issued $250 million of 4.30 percent 2014 Series A First Mortgage Bonds, due to mature in April 2044. The proceeds, net of issuance costs, were used to repay short-term borrowings. In accordance with ~~short-term debt. As a result, the PCRBs~~applicable accounting guidance, Notes Payable of $247.4 million were ~~recorded~~classified as Long-Term Debt ~~- Current Portion.~~on NU’s balance sheet as of March 31, 2014.

Working Capital: Each of NU, CL&P, NSTAR Electric, PSNH and WMECO use ~~their~~its available capital resources to fund ~~their~~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 ~~operate in an environment where recovery of its~~recover their electric and natural gas distribution construction expenditures ~~takes place~~as the related project costs are depreciated over ~~an extended period~~the life of ~~time.~~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 ~~NU’s~~ current liabilities exceeding current assets by approximately ~~$1.7 billion, $231~~$424 million, ~~$226 million, $34~~$355 million and ~~$48~~$177 million at NU, CL&P and NSTAR Electric, ~~PSNH and WMECO,~~ respectively, as of March 31, ~~2013.~~2014.

As of March 31, ~~2013, $947.3~~2014, $501.7 million of ~~NU's~~NU’s obligations classified as current liabilities relates to long-term debt that will be paid in the next 12 months, consisting of ~~$550 million for NU parent, $125~~$150 million for CL&P, ~~$109~~$301.7 million for ~~PSNH, $75~~NSTAR Electric and $50 million for ~~Yankee Gas and $55 million for WMECO. Approximately $32~~PSNH. In addition, $28.8 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, ~~as deemed appropriate given~~determined considering capital requirements and maintenance of ~~NU's~~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.

7.30

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7.PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

NUSCO sponsors a defined benefit retirement plan that covers most employees, including CL&P, PSNH, and WMECO employees, hired before 2006 (or as negotiated, for bargaining unit employees), referred to as the NUSCO Pension Plan. NSTAR Electric serves as plan sponsor for a defined benefit retirement plan that covers most employees of NSTAR Electric & Gas, hired before October 1, 2012, or as negotiated by bargaining unit employees, referred to as the NSTAR Pension Plan. Both plans are subject to the provisions of ERISA, as amended by the PPA of 2006. NUSCO and NSTAR Electric & Gas each maintain SERPs and other non-qualified defined benefit retirement plans (herein collectively referred to as the SERP Plans), which provide benefits in excess of Internal Revenue Code limitations to eligible current and retired participants that would have otherwise been provided under the Pension Plans.

NUSCO and NSTAR Electric & Gas also sponsor postretirement benefit plans that provide retiree medical, dental and life insurance benefits to employees that meet certain age and service eligibility requirements (NUSCO PBOP Plans and NSTAR PBOP Plan, respectively). Under certain circumstances, eligible retirees are required to contribute to the costs of postretirement benefits. The benefits provided under the NUSCO and NSTAR PBOP Plans are not vested and the Company has the right to modify any benefit provision.

The funded status of each of the plans is recorded on the respective sponsor's balance sheet: NUSCO (NUSCO Pension, NUSCO PBOP and NUSCO SERP), NSTAR Electric (NSTAR Pension) and NSTAR Electric & Gas (NSTAR SERP and NSTAR PBOP). The NUSCO plans are accounted for under the multiple-employer approach and the NSTAR plans are accounted for under the multi-employer approach. Accordingly, the balance sheet of NSTAR Electric reflects the full funded status of the NSTAR Pension Plan.

The components of net periodic benefit expense for the Pension, ~~Plans (including the~~ SERP ~~Plans)~~ and PBOP Plans are detailed below. The net periodic benefit expense less the capitalized portion of pension and PBOP amounts ~~capitalized related~~is included in Operations and Maintenance on the statements of income. Capitalized pension and PBOP amounts relate to employees working on capital projects and ~~intercompany~~are included in Property, Plant and Equipment, Net. Intercompany allocations are not included in the net periodic benefit expense ~~are as follows:~~amounts.


		Pension and SERP				Pension and SERP
		For the Three Months Ended				For the Three Months Ended
		March 31, 2013		March 31, 2012		March 31, 2014			March 31, 2013
(Millions of Dollars)	(Millions of Dollars)	NU		NU		NU			NU
Service Cost	Service Cost	$	26.6	$	15.3	$	22.3		$	26.6
Interest Cost	Interest Cost		51.4		38.1	56.6			51.4
Expected Return on Plan Assets	Expected Return on Plan Assets		(70.3)		(42.5)	(77.7		)	(70.3		)
Actuarial Loss	Actuarial Loss		52.9		30.1	33.0			52.9
Prior Service Cost	Prior Service Cost		1.1		2.1	1.1			1.1
Total Net Periodic Benefit Expense	Total Net Periodic Benefit Expense	$	61.7	$	43.1	$	35.3		$	61.7
Capitalized Pension Expense	Capitalized Pension Expense	$	16.7	$	10.6	$	9.7		$	16.7

	PBOP
	For the Three Months Ended
	March 31, 2014			March 31, 2013
(Millions of Dollars)	NU			NU
Service Cost	$	3.0		$	4.8
Interest Cost	12.6			12.8
Expected Return on Plan Assets	(15.7		)	(13.8		)
Actuarial Loss	3.0			8.2
Prior Service Credit	(0.6		)	(0.6		)
Total Net Periodic Benefit Expense	$	2.3		$	11.4
Capitalized PBOP Expense	$	0.4		$	3.5

	Pension and SERP
	For the Three Months Ended March 31, 2014												For the Three Months Ended March 31, 2013
				NSTAR												NSTAR
(Millions of Dollars)	CL&P			Electric			PSNH			WMECO			CL&P			Electric(1)			PSNH			WMECO
Service Cost	$	5.2		$	4.6		$	2.8		$	1.0		$	6.1		$	9.3		$	3.3		$	1.2
Interest Cost	13.3			10.2			6.5			2.7			12.1			14.2			6.0			2.5
Expected Return on Plan Assets	(19.4		)	(15.8		)	(10.2		)	(4.6		)	(18.5		)	(22.0		)	(7.7		)	(4.3		)
Actuarial Loss	9.1			5.8			3.3			1.9			14.1			14.5			5.5			3.0
Prior Service Cost	0.5			—			0.2			0.1			0.5			—			0.1			0.1
Total Net Periodic Benefit Expense	$	8.7		$	4.8		$	2.6		$	1.1		$	14.3		$	16.0		$	7.2		$	2.5
Intercompany Allocations	$	6.8		$	2.4		$	1.9		$	1.3		$	10.7		$	(2.0	)	$	2.6		$	1.8
Capitalized Pension Expense	$	4.9		$	1.9		$	0.9		$	0.8		$	7.0		$	5.3		$	2.2		$	1.3

	PBOP
	For the Three Months Ended March 31, 2014												For the Three Months Ended March 31, 2013
(Millions of Dollars)	CL&P			NSTAR Electric			PSNH			WMECO			CL&P			PSNH			WMECO
Service Cost	$	0.6		$	0.7		$	0.4		$	0.1		$	0.9		$	0.6		$	0.2
Interest Cost	2.1			4.9			1.1			0.5			2.0			1.0			0.4
Expected Return on Plan Assets	(2.7		)	(6.4		)	(1.4		)	(0.6		)	(2.5		)	(1.3		)	(0.6		)
Actuarial Loss/(Gain)	1.1			(0.1		)	0.5			0.1			1.7			0.9			0.3
Prior Service Credit	—			(0.5		)	—			—			—			—			—
Total Net Periodic Benefit Expense/(Income)	$	1.1		$	(1.4	)	$	0.6		$	0.1		$	2.1		$	1.2		$	0.3
Intercompany Allocations	$	1.1		$	0.1		$	0.3		$	0.2		$	1.6		$	0.4		$	0.3
Capitalized PBOP Expense/(Income)	$	0.5		$	(0.5	)	$	0.2		$	0.1		$	1.2		$	0.3		$	0.2

PBOP

For the Three Months Ended

March 31, 2013

March 31, 2012
(Millions of Dollars)
NU

NU
Service Cost
$
4.8

$
2.3
Interest Cost

12.8

6.2
Expected Return on Plan Assets

(13.8)

(5.6)
Actuarial Loss

8.2

5.5
Prior Service Credit

(0.6)

(0.1)
Net Transition Obligation Cost

-

2.9
Total Net Periodic Benefit Expense
$
11.4

$
11.2

Pension and SERP

For the Three Months Ended March 31, 2013

For the Three Months Ended March 31, 2012

NSTAR

NSTAR

(Millions of Dollars)
CL&P

Electric

PSNH

WMECO

CL&P

Electric⁽¹⁾

PSNH

WMECO
Service Cost
$
6.1

$
9.3

$
3.3

$
1.2

$
5.4

$
7.8

$
2.9

$
1.1
Interest Cost

12.1

14.2

6.0

2.5

12.8

14.8

6.1

2.6
Expected Return on Plan Assets

(18.5)

(22.0)

(7.7)

(4.3)

(17.5)

(16.5)

(6.7)

(4.1)
Actuarial Loss

14.1

14.5

5.5

3.0

11.9

15.7

3.9

2.5
Prior Service Cost/(Credit)

0.5

-

0.1

0.1

0.9

(0.2)

0.4

0.2
Total Net Periodic Benefit Expense
$
14.3

$
16.0

$
7.2

$
2.5

$
13.5

$
21.6

$
6.6

$
2.3
Related Intercompany

Allocations
$
10.7

$
(2.0)

$
2.6

$
1.8

$
10.6

$
(3.1)

$
2.5

$
2.0
Capitalized Pension Expense
$
7.0

$
5.3

$
2.2

$
1.3

$
6.6

$
6.3

$
2.0

$
1.2

PBOP

For the Three Months Ended March 31, 2013

For the Three Months Ended March 31, 2012
(Millions of Dollars)
CL&P

PSNH

WMECO

CL&P

PSNH

WMECO
Service Cost
$
0.9

$
0.6

$
0.2

$
0.8

$
0.5

$
0.2
Interest Cost

2.0

1.0

0.4

2.4

1.2

0.5
Expected Return on Plan Assets

(2.5)

(1.3)

(0.6)

(2.3)

(1.1)

(0.5)
Actuarial Loss

1.7

0.9

0.3

2.0

1.0

0.3
Net Transition Obligation Cost

-

-

-

1.5

0.6

0.3
Total Net Periodic Benefit Expense
$
2.1

$
1.2

$
0.3

$
4.4

$
2.2

$
0.8
Related Intercompany

Allocations
$
1.6

$
0.4

$
0.3

$
2.1

$
0.5

$
0.4

⁽¹⁾

NSTAR ~~Electric~~Electric’s pension amounts ~~are not included in NU consolidated for the three months ended March 31, 2012.~~

For the NSTAR PBOP Plan, NSTAR allocates the net periodic postretirement expenses to its subsidiaries based on actual labor charges to each of its subsidiaries. The net periodic postretirement expense allocated to NSTAR Electric was $4.3 million and $9 million for the three months ended March 31, 2013 ~~and 2012, respectively. The three months ended March 31, 2012 amount was~~do not ~~included in NU consolidated.~~include SERP expense.

~~Contributions:~~NU’s policy is to annually fund the NUSCO and NSTAR Pension Plans in an amount at least equal to an amount that will satisfy federal requirements. Based on the current status of the NUSCO Pension Plan, NU anticipates making a contribution of approximately $203 million in 2013, of which $107 million is required to meet minimum federal funding requirements. NSTAR Electric anticipates making a contribution of approximately $82 million in 2013 to the NSTAR Pension Plan, of which $38 million is required to meet minimum federal funding requirements. Contributions are being made in installments and began in January 2013. For the three months ended March 31, 2013, ~~NU contributed $35.1 million~~the net periodic PBOP expense allocated to ~~the NUSCO Pension Plan, all of which was contributed by PSNH, and~~ NSTAR Electric ~~contributed~~was $4.3 ~~million to~~million.

As of December 31, 2013, the funded status of the NSTAR Pension ~~Plan.~~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.

~~For~~As of March 31, 2014, the liabilities associated with the Pension, SERP and PBOP plans for NSTAR Electric were $74.8 million for the Pension Plan, $3.5 million for the SERP Plans ($0.4 million of which is included in other current liabilities) and $73 million for the PBOP ~~Plans, it is NU’s policy to annually fund~~

Table of Contents

Plan. As of December 31, 2013, the NUSCO PBOP Plans in an amount equal to the PBOP Plans' postretirement benefit cost, excluding curtailment and termination benefits, if applicable. NU anticipates making $25.7 million in contributions in 2013. NU contributes an amount that approximates annual benefit payments toliability associated with the NSTAR ~~PBOP Plan. NU anticipates making $30 million in contributions in 2013, of which $7.5 million~~Pension Plan for NSTAR Electric was ~~contributed during the three months ended March 31, 2013.~~

~~INCOME TAXES~~

~~Tax Positions:~~ InMarch 2013, NU received a Final Determination from the Connecticut Department of Revenue Services (DRS) Appellate Division that concluded its audit of NU's Connecticut income tax returns for the years 2005 through 2008, bringing closure to, and effective settlement of, issues concerning the deductibility of expenses and credits through 2008. The DRS Determination resulted in total NU and CL&P after-tax benefits of $13.6 million and $6.9 million, respectively, recorded in the first quarter of 2013 that included a reduction in NU and CL&P pre-tax interest expense of $8.7 million and $4 million, or $5.2 million and $2.4 million after-tax, respectively. Further,$118 million. This change had no impact on the income ~~tax expense impact resulted in a tax benefit to NU and CL&P~~statement or net assets of $8.4 million and $4.5 million after-tax, respectively. Management estimates that resolution of this audit decreases NU's and CL&P's unrecognized tax benefits by approximately $49.8 million and $39.4 million, respectively, that was largely offset by NU's and CL&P's valuation allowance and other tax impacts of $44.9 million and $36.5 million, respectively. NSTAR Electric.

NU currently has open tax years. It is reasonably possible that at least one of these open tax years could be resolved within the next twelve months. Management estimates that the potential resolutions could result in a $1 million to $2 million decrease, net of any related valuation allowance, in unrecognized tax benefits for NU.

8.COMMITMENTS AND CONTINGENCIES

Environmental Matters

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

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


	As of March 31, 2013				As of December 31, 2012				As of March 31, 2014			As of December 31, 2013
			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		72	$	40.7		77	$	39.4	66	$	35.4	68	$	35.4
CL&P		19		3.6		19		3.7	18	3.4		18	3.4
NSTAR Electric		14		1.5		16		1.7	12	1.2		12	1.2
PSNH		16		5.6		16		4.9	13	5.4		15	5.4
WMECO		5		0.5		6		0.6	5	0.4		5	0.4

Included in the NU number of sites and reserve amounts above are former MGP sites that were operated several decades ago and manufactured gas from coal and other processes, which resulted in certain by-products remaining in the environment that may pose a potential risk to human health and the environment. The reserve balance related to these former MGP sites was ~~$34.3~~$30.9 million and ~~$34.5~~$31.4 million as of March 31, ~~2013~~2014 and December 31, ~~2012,~~2013, respectively, and relates primarily to the natural gas business segment.

B.Contractual Obligations — Yankee Companies

~~HWP:~~Spent Nuclear Fuel Litigation - DOE Phase II Damages ~~HWP,~~ - 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 ~~subsidiary~~letter from the U.S. Department of ~~NU, continues to investigate~~Justice stating that the ~~potential need for additional remediation at a river site~~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 28, 2014, the Yankee Companies made the required informational filing with FERC in ~~Massachusetts containing tar deposits associated~~accordance with ~~an MGP site~~the process and methodology outlined in the 2013 FERC order. It is anticipated that ~~HWP sold to HG&E, a municipal utility, dating back to 1902. HWP shares responsibility for site remediation with HG&E~~the Yankee Companies will receive FERC approval and ~~has conducted substantial investigative and remediation activities. The cumulative expense recorded~~return the DOE Phase II Damages proceeds to the reserve for this site since 1994 through March 31, 2013 was $19.5 million, of which $17.5 million had been spent, leaving $2 million in the reserve as of March 31, 2013. There were no charges recorded to the reserve for the three months ended March 31, 2013 and 2012. HWP's share of the costs related to this site is not recoverable from customers.

~~The $2 million reserve balance as of March 31, 2013 represents estimated costs that HWP considers probable over the remaining life of the project,~~member companies, including testing and related costs in the near term and field activities to be agreed upon with the MA DEP, further studies and long-term monitoring that are expected to be required by the MA DEP, and certain soft tar remediation activities. Various factors could affect management's estimates and require an increase to the reserve, which would be reflected as a charge to Net Income. Although a material increase to the reserve is not presently anticipated, management cannot reasonably estimate potential additional investigation or remediation costs because these costs would depend on, among other things, the nature, extent and timing of additional investigation and remediation that may be required by the MA DEP.

~~Deferred Contractual Obligations~~

CL&P, NSTAR Electric, PSNH, and WMECO, have decommissioning and plant closure cost obligations to the Yankee Companies, which have each completed the physical decommissioning of their respective nuclear facilities and are now engaged in the long-term storage of their spent fuel. The Yankee Companies collect decommissioning and closure costs through wholesale, FERC-approved rates charged under power purchase agreements with several New England utilities, including CL&P, NSTAR Electric, PSNH and WMECO. These companies in turn recover these costs from their customers through state regulatory commission-approved retail rates.

CL&P, NSTAR Electric, PSNH and WMECO's percentage share of the obligations to support the Yankee Companies under FERC-approved rate tariffs is the same as their respective ownership percentages in the Yankee Companies.

The Yankee Companies are currently collecting amounts that management believes are adequate to recover the remaining decommissioning and closure cost estimates for the respective plants. Management believes CL&P, NSTAR Electric and WMECO will recover their shares of these decommissioning and closure obligations from their customers. PSNH has already recovered its share of these costs from its customers.

~~Spent Nuclear Fuel Litigation:~~

~~DOE Phase I Damages~~ - In 1998, the Yankee Companies filed separate complaints against the DOE in the Court of Federal Claims seeking monetary damages resulting from the DOE's failure to begin accepting spent nuclear fuel for disposal by January 31, 1998 pursuant to the terms of the 1983 spent fuel and high level waste disposal contracts between the Yankee Companies and the DOE (DOE Phase I Damages). Following multiple appeals filed by the DOE and cross-appeals filed by the Yankee Companies, on September 5, 2012, the judgment to award CYAPC $39.7 million, YAEC $38.2 million and MYAPC $81.7 million became final and non-appealable and interest on the judgments began to accrue on or about December 5, 2012.

In January 2013, the proceeds from the DOE Phase I Damages Claim were received by CYAPC in the amount of $39.7 million, YAEC in the amount of $38.2 million, and MYAPC in the amount of $81.7 million. The funds were transferred to each Yankee Company’s respective decommissioning trust. As a result of NU's consolidation of CYAPC and YAEC, the consolidated financial statements reflect an increase of $77.9 million in marketable securities for CYAPC and YAEC’s Phase I damage awards that were invested in the nuclear decommissioning trusts as of March 31, 2013.

~~The final application of the proceeds~~ for the benefit of their respective customers, effective June 1, 2014.

As of ~~CL&P, NSTAR Electric, PSNH~~March 31, 2014, the CYAPC and ~~WMECO will be determined following rate proceedings that were~~YAEC proceeds received have been reflected as restricted cash in Other Long-Term Assets and the refund obligation to the member companies was reflected as Regulatory Liabilities on the NU consolidated balance sheet.

DOE Phase III Damages - On August 15, 2013, the Yankee Companies each filed ~~by each Yankee Company at FERC~~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 ~~May 1, 2013. Final FERC determinations are expected by the end of the third quarter of 2013.~~November 18, 2013, and discovery has begun.

Guarantees and Indemnifications

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

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

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

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

Table of Contents

The following table summarizes ~~NU's~~NU’s guarantees of its subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, as of March 31, ~~2013:~~ 2014:


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

Various	Surety Bonds	$	33.1		2013 - 2015 (1)	Surety Bonds	$	66.7	2014 - 2016 (1)

Various	NE Hydro Companies' Long-Term Debt	$	5.6		Unspecified	New England Hydro Companies’ Long-Term Debt	$	3.0	Unspecified

NUSCO and RRR	Lease Payments for Vehicles and Real Estate	$	19.2		2019 and 2024	Lease Payments for Vehicles and Real Estate	$	16.8	2019 and 2024

NU Enterprises	Surety Bonds, Insurance Bonds and Performance Guarantees	$	67.8	(2)	(2)

⁽¹⁾

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

⁽²⁾

The maximum exposure includes $8.4 million related to performance guarantees on wholesale purchase contracts, which expire December 31, 2013. Also included in the maximum exposure is $1 million related to insurance bonds with no expiration date that are billed annually on their anniversary date. The remaining $58.4 million of maximum exposure relates to surety bonds covering ongoing projects, which expire upon project completion.

~~Many of the underlying contracts that NU parent guarantees, as well as certain~~Certain surety bonds contain credit ratings triggers that would require NU parent to post collateral in the event that the unsecured debt credit ratings of NU ~~or NSTAR LLC, as applicable,~~ are downgraded.

FERC Base ROE Complaint

On September 30, 2011, several New England state attorneys general, state regulatory commissions, consumer advocates and other parties filed a joint complaint with the FERC under Sections 206 and 306 of the Federal Power Act alleging that the base ROE used in calculating formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by ~~New England transmission owners,~~NETOs, including CL&P, NSTAR Electric, PSNH and WMECO, is unjust and unreasonable. The complainants asserted that the current 11.14 percent rate, which became effective in 2006, is excessive due to changes in the capital markets and are seeking an order to reduce the rate, which would be effective October 1, 2011. In response, the ~~New England transmission owners~~NETOs filed testimony and analysis based on standard FERC methodology and precedent demonstrating that the base ROE of 11.14 percent remained just and reasonable. The FERC set the case for trial before a FERC ~~administrative law judge~~ALJ after settlement negotiations were unsuccessful in August ~~2012~~.2012.

~~As part~~Hearings before the FERC ALJ were held in May 2013, followed by the filing of ~~the pre-trial process, on April 17, 2013,~~briefs by the complainants, the Massachusetts municipal electric utilities (late ~~intervenors~~interveners to the case), the FERC trial staff and the NETOs. The NETOs recommended that the current base ROE of 11.14 percent should remain in effect for the refund period (October 1, 2011 through December 31, 2012) and the prospective period (beginning when FERC issues its final decision). The complainants, the Massachusetts municipal electric utilities, and the FERC trial staff ~~updated their respective ROE analyses, which demonstrated~~each recommended a base ROE of ~~approximately 8.9 percent. The New England transmission owners also filed~~9 percent or below.

On August 6, 2013, the FERC ALJ issued an ~~updated analysis, including a supplement on April 26, 2013, that continues to demonstrate~~initial decision, finding that the ~~current~~base ROE in effect from October 2011 through December 2012 was not reasonable under the standard application of ~~11.14~~FERC methodology, but leaving policy considerations and additional adjustments to the FERC. Using the established FERC methodology, the FERC ALJ determined that separate base ROEs should be set for the refund period and the prospective period. The FERC ALJ found those base ROEs to be 10.6 percent ~~remains within an updated range~~and 9.7 percent, respectively. The FERC may adjust the prospective period base ROE in its final decision to reflect movement in 10-year Treasury bond rates from the date that the case was filed (April 2013) to the date of ~~reasonableness of 7.3 percent to 13.2 percent. Hearings~~the final decision. The parties filed briefs on this ~~complaint are scheduled to commence on May 6, 2013~~decision with the FERC, and ~~the trial judge’s recommended decision is due in September 2013. A~~a decision from the FERC ~~commissioners~~ is expected in 2014. ~~Refunds~~Though NU cannot predict the ultimate outcome of this proceeding, in 2013 the Company recorded a series of reserves at its electric subsidiaries to ~~customers, if any, as a result of a reduction in~~recognize the ~~NU transmission companies’ base ROE would be~~potential financial impact from the FERC ALJ’s initial decision for the ~~period October 1, 2011 through December 31, 2012.~~refund period. The aggregate after-tax charge to earnings totaled $14.3 million at NU, which represents 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 December 27, 2012, several additional parties filed a separate complaint concerning the ~~New England transmission owners'~~NETOs’ base ROE with the FERC. This ~~new~~ complaint seeks to reduce the ~~New England transmission owners’~~NETOs’ base ROE effective January 1, 2013, effectively extending the refund period for an additional 15 months, and to consolidate this ~~new~~ complaint with the joint complaint filed on September 30, 2011. The ~~New England transmission owners~~NETOs have asked the FERC to reject this ~~new~~ complaint. The FERC has not yet acted on this ~~request.~~complaint, and management is unable to predict the ultimate outcome or estimate the impacts of this complaint on the financial position, results of operations or cash flows.

E.Management expects the CL&P, NSTAR Electric, PSNH, and WMECO aggregate shareholder equity invested in their transmission facilities will be approximately $2.4 billion at the end of 2014. As a result, each 10 basis point change in the prospective period authorized base ROE would change annual consolidated earnings by an approximate $2.4 million.

~~DPU Safety and Reliability Programs -~~

E.CPSL ~~(NSTAR Electric)~~

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

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

NSTAR Electric cannot predict the timing of a final DPU order related to its CPSL filings for the period 2006 through 2011. ~~Therefore, NSTAR Electric recorded its 2006 through 2011 revenues under the CPSL programs based on the May 2010 Order.~~ While management does not believe that any subsequent DPU order would result in revenues that are materially different than the amounts

Table of Contents

already recognized, it is reasonably possible that an order could have a material impact on NSTAR Electric’s results of operations, financial position and cash flows.

Basic Service Bad Debt Adder ~~(NSTAR Electric)~~

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

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

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

~~10.~~

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 and Rate Reduction Bonds:~~Debt: The fair value of CL~~&P's~~&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 ~~and RRBs~~ 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 March 31, 2013				As of December 31, 2012				As of March 31, 2014				As of December 31, 2013
		NU				NU				NU				NU
		Carrying		Fair		Carrying		Fair		Carrying		Fair		Carrying		Fair
(Millions of Dollars)	(Millions of Dollars)	Amount		Value		Amount		Value		Amount		Value		Amount		Value
Preferred Stock Not	Preferred Stock Not
Subject to Mandatory Redemption										$	155.6	$	152.0	$	155.6	$	152.7
Long-Term Debt										8,848.9		9,177.7		8,310.2		8,443.1
	Subject to Mandatory Redemption	$	155.6	$	154.2	$	155.6	$	152.2
Long-Term Debt			7,958.9		8,634.1		7,963.5		8,640.7
Rate Reduction Bonds			19.6		19.7		82.1		83.0

	As of March 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	$	110.9	$	43.0	$	41.1	$	—	$	—	$	—	$	—
Long-Term Debt	2,741.4		3,033.1		2,099.0		2,224.0		1,049.1		1,096.5		629.2		661.0

	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

As of March 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

$
111.6

$
43.0

$
42.6

$
-

$
-

$
-

$
-
Long-Term Debt

2,865.6

3,295.9

1,602.6

1,809.0

998.0

1,091.6

605.1

665.0
Rate Reduction Bonds

-

-

-

-

15.0

15.0

4.6

4.7

As of December 31, 2012

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

$
110.0

$
43.0

$
42.2

$
-

$
-

$
-

$
-
Long-Term Debt

2,862.8

3,295.4

1,602.6

1,818.8

997.9

1,088.0

605.3

660.4
Rate Reduction Bonds

-

-

43.5

43.9

29.3

29.6

9.4

9.5

Derivative Instruments: ~~NU, including CL&P, NSTAR Electric and WMECO, holds various derivative~~Derivative instruments ~~that~~ are carried at fair value. For further information, see Note 4, ~~"Derivative~~“Derivative Instruments,"” to the ~~consolidated~~ financial statements.

Other Financial Instruments: Investments in marketable securities are carried at fair ~~value on the accompanying consolidated balance sheets.~~value. For further information, see Note ~~1E, "Summary~~1D, “Summary of Significant Accounting Policies - Fair Value Measurements,"” and Note 5, ~~"Marketable~~“Marketable Securities,"” to the ~~consolidated~~ 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.

~~11.~~34

Table of Contents

10.ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)

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

For the Three Months Ended March 31, 2013
(Millions of Dollars)
Qualified Cash Flow Hedging Instruments

Unrealized Gains/(Losses) on Available-for-Sale Securities

Pension, SERP and PBOP
Benefit Plans

Total
AOCI as of January 1, 2013
$
(16.4)

$
1.3

$
(57.8)

$
(72.9)

Other Comprehensive Income Before Reclassifications

-

(0.1)

-

(0.1)
Amounts Reclassified from AOCI

0.5

-

1.6

2.1
Net Other Comprehensive Income

0.5

(0.1)

1.6

2.0
AOCI as of March 31, 2013
$
(15.9)

$
1.2

$
(56.2)

$
(70.9)

	For the Three Months Ended March 31, 2014											For the Three Months Ended March 31, 2013
				Unrealized		Pension,									Unrealized			Pension,
	Qualified			Gains/(Losses)		SERP and						Qualified			Gains/(Losses)			SERP and
	Cash Flow			on Available-		PBOP						Cash Flow			on Available-			PBOP
	Hedging			for-Sale		Benefit						Hedging			for-Sale			Benefit
(Millions of Dollars)	Instruments			Securities		Plans			Total			Instruments			Securities			Plans			Total
AOCI as of Beginning of Period	$	(14.4	)	$	0.4	$	(32.0	)	$	(46.0	)	$	(16.4	)	$	1.3		$	(57.8	)	$	(72.9	)

OCI Before Reclassifications	—			0.2		—			0.2			—			(0.1		)	—			(0.1		)
Amounts Reclassified from AOCI	0.5			—		1.0			1.5			0.5			—			1.6			2.1
Net OCI	0.5			0.2		1.0			1.7			0.5			(0.1		)	1.6			2.0
AOCI as of End of Period	$	(13.9	)	$	0.6	$	(31.0	)	$	(44.3	)	$	(15.9	)	$	1.2		$	(56.2	)	$	(70.9	)

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

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


	~~For the Three Months Ended March 31, 2013~~
	~~Amount~~
	~~Reclassified~~		~~Statement of Income~~
~~(Millions of Dollars)~~	~~from AOCI~~		~~Line Item Impacted~~
~~Qualified Cash Flow Hedging Instruments~~	$	~~(0.8)~~	~~Interest Expense~~
~~Tax Benefit~~		~~0.3~~	~~Income Tax Expense~~
~~Qualified Cash Flow Hedging Instruments, Net of Tax~~	$	~~(0.5)~~

~~Pension, SERP and PBOP Benefit Plan Costs:~~
~~Amortization of Actuarial Losses~~	$	~~(2.6)~~	⁽¹⁾
~~Amortization of Prior Service Cost~~		-	⁽¹⁾
~~Total Pension, SERP and PBOP Benefit Plan Costs~~		~~(2.6)~~	⁽¹⁾
~~Tax Benefit~~		~~1.0~~	~~Income Tax Expense~~
~~Pension, SERP and PBOP Benefit Plan Costs, Net of Tax~~	$	~~(1.6)~~

~~Total Amount Reclassified from AOCI, Net of Tax~~	$	~~(2.1)~~

	For the Three Months Ended March 31,
	Amounts Reclassified from AOCI						Statements of Income Line Item Impacted
(Millions of Dollars)	2014			2013
Qualified Cash Flow Hedging Instruments	$	(0.8	)	$	(0.8	)	Interest Expense
Tax Benefit	0.3			0.3			Income Tax Expense
Qualified Cash Flow Hedging Instruments, Net of Tax	$	(0.5	)	$	(0.5	)

Pension, SERP and PBOP Benefit Plan Costs:
Amortization of Actuarial Losses	$	(1.7	)	$	(2.6	)	Operations and Maintenance (1)
Tax Benefit	0.7			1.0			Income Tax Expense
Pension, SERP and PBOP Benefit Plan Costs, Net of Tax	$	(1.0	)	$	(1.6	)

Total Amount Reclassified from AOCI, Net of Tax	$	(1.5	)	$	(2.1	)

⁽¹⁾

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

~~12.~~
11.COMMON SHARES

The following table sets forth the NU common shares and the shares of common stock of CL&P, NSTAR Electric, PSNH and WMECO ~~common stock~~that were authorized and issued ~~as of March 31, 2013 and December 31, 2012~~ and the respective per share par values:

Shares

Shares

Authorized

Issued

Authorized as of

Per Share

As of

As of

Per Share

March 31, 2014 and

Issued as of

Par Value

March 31, 2013

December 31, 2012

March 31, 2013

December 31, 2012

Par Value

December 31, 2013

March 31, 2014

December 31, 2013

NU
$
5

380,000,000

380,000,000

332,951,956

332,509,383

$
5

380,000,000

333,316,045

333,113,492

CL&P
$
10

24,500,000

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

100,000,000

100

100

$
1

100,000,000

100

100

PSNH
$
1

100,000,000

100,000,000

301

301

$
1

100,000,000

301

301

WMECO
$
25

1,072,471

1,072,471

434,653

434,653

$
25

1,072,471

434,653

434,653

As of March 31, ~~2013~~2014 and December 31, ~~2012, 18,356,487~~2013, there were 17,498,327 and ~~18,455,749~~17,796,672 NU common shares ~~were~~ held as treasury shares, respectively. As of March 31, 2014 and December 31, 2013, NU common shares outstanding were 315,817,718 and 315,273,559, respectively.

13.
COMMON SHAREHOLDERS' EQUITY AND NONCONTROLLING INTERESTS (NU)

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

For the Three Months Ended

March 31, 2013

March 31, 2012

Noncontrolling

Noncontrolling

Interest -

Interest -

Common

Preferred

Common

Non-

Preferred

Shareholders'

Stock of

Shareholders'

Controlling

Total

Stock of

(Millions of Dollars)
Equity

Subsidiaries

Equity

Interest

Equity

Subsidiaries

Balance - Beginning of Period
$
9,237.1

$
155.6

$
4,012.7

$
3.0

$
4,015.7

$
116.2

Net Income

230.0

-

100.8

-

100.8

-

Dividends on Common Shares

(116.4)

-

(52.6)

-

(52.6)

-

Dividends on Preferred Stock

(1.9)

(1.9)

(1.4)

-

(1.4)

(1.4)

Issuance of Common Shares

8.4

-

6.2

-

6.2

-

Contributions to NPT

-

-

-

0.3

0.3

-

Other Transactions, Net

(14.0)

-

0.8

-

0.8

-

Net Income Attributable to

Noncontrolling Interests

-

1.9

(0.1)

0.1

-

1.4

Other Comprehensive Income

2.0

-

1.9

-

1.9

-

Balance - End of Period
$
9,345.2

$
155.6

$
4,068.3

$
3.4

$
4,071.7

$
116.2

~~14.~~35

Table of Contents

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
	March 31, 2014						March 31, 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	237.8			—			230.0			—
Dividends on Common Shares	(123.9		)	—			(116.4		)	—
Dividends on Preferred Stock	(1.9		)	(1.9		)	(1.9		)	(1.9		)
Issuance of Common Shares	5.2			—			8.4			—
Other Transactions, Net	(6.5		)	—			(14.0		)	—
Net Income Attributable to Noncontrolling Interests	—			1.9			—			1.9
Other Comprehensive Income	1.7			—			2.0			—
Balance as of End of Period	$	9,723.9		$	155.6		$	9,345.2		$	155.6

13.EARNINGS PER SHARE ~~(NU)~~

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 ifof certain share-based compensation awards ~~are~~as if they were converted into common shares. There were no antidilutive share awards outstanding for the three months ended March 31, 2014. For the three months ended March 31, 2013, there were 6,299 antidilutive share awards excluded from the ~~computation as these awards were antidilutive. There were no antidilutive share awards for the three months ended March 31, 2012.~~ computation.

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


		For the Three Months Ended March 31,				For the Three Months Ended
(Millions of Dollars, except share information)	(Millions of Dollars, except share information)	2013		2012		March 31, 2014		March 31, 2013
Net Income Attributable to Controlling Interest	Net Income Attributable to Controlling Interest	$	228.1	$	99.3	$	236.0	$	228.1

Weighted Average Common Shares Outstanding:	Weighted Average Common Shares Outstanding:
	Basic		315,129,782		178,055,716
	Dilutive Effect		872,756		381,737
	Diluted		316,002,538		178,437,453
Basic and Diluted EPS		$	0.72	$	0.56
Basic						315,534,512		315,129,782
Dilutive Effect						1,357,607		872,756
Diluted						316,892,119		316,002,538
Basic EPS						$	0.75	$	0.72
Diluted EPS						$	0.74	$	0.72

~~On April 10, 2012, NU issued approximately 136 million common shares as a result of the merger with NSTAR, which are reflected in weighted average common shares outstanding as of March 31, 2013.~~

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

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

~~15.~~

14.SEGMENT INFORMATION ~~(NU)~~

Presentation: NU is organized between the Electric Distribution, Electric Transmission and Natural Gas Distribution reportable segments and Other based on a combination of factors, including the characteristics of each ~~segments'~~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~~NU’s total consolidated revenues for the three ~~month periods~~months ended March 31, ~~2013~~2014 and ~~2012.~~2013. Revenues from the sale of electricity and natural gas primarily are derived from residential, commercial and industrial customers and are not dependent on any single customer. The Electric Distribution reportable segment includes the generation activities of PSNH and WMECO.

The remainder of NU’s operations is presented as Other ~~operations~~ in the tables below and primarily consists of 1) the equity in earnings of NU parent from its subsidiaries and intercompany interest income, both of which are eliminated in consolidation, and interest ~~income and~~ expense related to the ~~cash and~~ debt of NU parent, ~~and NSTAR LLC, respectively,~~ 2) the revenues and expenses of ~~NU's~~NU’s service ~~companies,~~company, most of which are eliminated in consolidation, 3) the operations of CYAPC and YAEC, and 4) the results of other non-regulated subsidiaries, which are ~~comprised~~not part of ~~NU Enterprises, NSTAR Communications, Inc., RRR (a real estate subsidiary), the non-energy-related subsidiaries~~its core business.

Table of ~~Yankee and the remaining operations of HWP.~~Contents

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.

As discussed in Note 1A, “Summary of Significant Accounting Policies – Basis of Presentation,” certain reclassifications of prior period data were made in the consolidated statements of income for NU. Accordingly, the corresponding items of segment information have been recast for prior periods for comparative purposes.

NU’s reportable segments are ~~the combined Electric Distribution, Electric Transmission and Natural Gas Distribution segments,~~determined based upon the level at which NU’s chief operating decision maker assesses performance and makes decisions about the allocation of company resources. Each of NU’s subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, has one reportable segment. ~~Therefore, separate Transmission and Distribution information is not disclosed for CL&P, NSTAR Electric, PSNH or WMECO.~~ NU’s operating segments and reporting units are consistent with its reportable business segments.

~~NSTAR amounts are not included in NU consolidated as of March 31, 2012, but are included as of March 31, 2013.~~

~~NU's~~NU’s segment information for the three ~~month periods~~months ended March 31, ~~2013~~2014 and ~~2012~~2013 is as follows:

For the Three Months Ended March 31, 2013

Electric

Natural Gas

(Millions of Dollars)
Distribution

Distribution

Transmission

Other

Eliminations

Total
Operating Revenues
$
1,374.2

$
361.8

$
239.5

$
217.2

$
(197.7)

$
1,995.0
Depreciation and Amortization

(177.0)

(17.4)

(31.8)

(19.0)

1.7

(243.5)
Other Operating Expenses

(1,004.9)

(267.2)

(62.2)

(197.4)

199.2

(1,332.5)
Operating Income

192.3

77.2

145.5

0.8

3.2

419.0
Interest Expense

(42.1)

(7.4)

(21.9)

(6.4)

1.5

(76.3)
Interest Income

1.0

-

0.1

1.6

(1.6)

1.1
Other Income, Net

3.8

0.2

2.7

320.3

(320.3)

6.7
Income Tax (Expense)/Benefit

(54.3)

(26.7)

(45.8)

6.5

(0.2)

(120.5)
Net Income

100.7

43.3

80.6

322.8

(317.4)

230.0
Net Income Attributable

to Noncontrolling Interests

(1.2)

-

(0.7)

-

-

(1.9)
Net Income Attributable

to Controlling Interest
$
99.5

$
43.3

$
79.9

$
322.8

$
(317.4)

$
228.1
Total Assets (as of)
$
18,208.2

$
2,735.4

$
6,269.1

$
18,749.8

$
(17,633.8)

$
28,328.7
Cash Flows Used for

Investments in Plant
$
157.8

$
31.2

$
185.4

$
14.6

$
-

$
389.0

	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

	For the Three Months Ended March 31, 2013
	Electric			Natural Gas
(Millions of Dollars)	Distribution			Distribution			Transmission			Other			Eliminations			Total
Operating Revenues	$	1,374.2		$	361.8		$	239.5		$	217.2		$	(197.7	)	$	1,995.0
Depreciation and Amortization	(177.0		)	(17.4		)	(31.8		)	(19.0		)	1.7			(243.5		)
Other Operating Expenses	(1,004.9		)	(267.2		)	(62.2		)	(197.4		)	199.2			(1,332.5		)
Operating Income	192.3			77.2			145.5			0.8			3.2			419.0
Interest Expense	(42.1		)	(7.4		)	(21.9		)	(6.4		)	1.5			(76.3		)
Other Income, Net	4.8			0.2			2.8			321.9			(321.9		)	7.8
Net Income Attributable to Controlling Interest	$	99.5		$	43.3		$	79.9		$	322.8		$	(317.4	)	$	228.1
Cash Flows Used for Investments in Plant	$	157.8		$	31.2		$	185.4		$	14.6		$	—		$	389.0

The following table summarizes NU’s segmented total assets:

	Electric		Natural Gas
(Millions of Dollars)	Distribution		Distribution		Transmission		Other		Eliminations			Total
As of March 31, 2014	$	18,882.9	$	2,846.7	$	5,165.6	$	11,913.6	$	(10,711.9	)	$	28,096.9
As of December 31, 2013	17,260.0		2,759.7		6,745.8		11,842.4		(10,812.4		)	27,795.5

15.SUBSEQUENT EVENT

See Note 6, “Short-Term and Long-Term Debt,” for information regarding the April 2014 CL&P long-term debt issuance.

For the Three Months Ended March 31, 2012

Electric

Natural Gas

(Millions of Dollars)
Distribution

Distribution

Transmission

Other

Eliminations

Total
Operating Revenues
$
786.0

$
139.0

$
162.8

$
133.3

$
(121.5)

$
1,099.6
Depreciation and Amortization

(72.2)

(7.7)

(21.1)

(3.9)

0.3

(104.6)
Other Operating Expenses

(622.1)

(102.2)

(47.6)

(134.9)

126.2

(780.6)
Operating Income/(Loss)

91.7

29.1

94.1

(5.5)

5.0

214.4
Interest Expense

(33.0)

(5.4)

(19.7)

(9.4)

1.1

(66.4)
Interest Income

1.1

-

0.1

1.3

(1.3)

1.2
Other Income, Net

4.4

-

3.3

122.6

(122.7)

7.6
Income Tax (Expense)/Benefit

(21.4)

(9.0)

(30.8)

6.0

(0.8)

(56.0)
Net Income

42.8

14.7

47.0

115.0

(118.7)

100.8
Net Income Attributable

to Noncontrolling Interests

(0.8)

-

(0.7)

-

-

(1.5)
Net Income Attributable

to Controlling Interest
$
42.0

$
14.7

$
46.3

$
115.0

$
(118.7)

$
99.3
Total Assets (as of)
$
9,553.3

$
1,498.2

$
3,900.7

$
7,261.7

$
(6,235.5)

$
15,978.4
Cash Flows Used for

Investments in Plant
$
130.7

$
20.5

$
135.9

$
17.2

$
-

$
304.3

Table of Contents

NORTHEAST UTILITIES AND ~~SUBSIDIAIRIES~~SUBSIDIARIES

~~Management's~~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 and the ~~2012~~2013 Annual Report on Form 10-K. References in this Form 10-Q to ~~"NU,"~~“NU,” the ~~"Company," "we," "us"~~“Company,” “we,” “us,” and ~~"our"~~“our” refer to Northeast Utilities and its consolidated ~~subsidiaries, including NSTAR LLC and its subsidiaries for the periods after April 10, 2012.~~subsidiaries. All per share amounts are reported on a diluted basis. The unaudited condensed consolidated financial statements of NU, ~~CL&P,~~ NSTAR Electric and PSNH and the unaudited condensed financial statements of CL&P and WMECO are herein collectively referred to as ~~“consolidated financial statements”.~~ the “financial statements.”

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

The only common equity securities that are publicly traded are common shares of NU. The earnings and EPS of each business discussed below do not represent a direct legal interest in the assets and liabilities allocated to such business but rather represent a direct interest in our assets and liabilities as a whole. EPS by business is a financial measure not recognized under GAAP that is calculated by dividing the Net Income Attributable to Controlling Interest of each business by the weighted average diluted NU common shares outstanding for the ~~period.~~year. The discussion below also includes non-GAAP financial measures referencing our first quarter ~~2013~~2014 and ~~2012~~2013 earnings and EPS excluding certain ~~impacts~~integration costs related to ~~NU's~~NU’s merger with NSTAR. We use these non-GAAP financial measures to evaluate and to provide details of earnings ~~results~~ by business and to more fully compare and explain our first quarter ~~2013~~2014 and ~~2012~~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~~“Financial Condition and Business Analysis –— Overview ~~– Consolidated"~~— Consolidated” in~~Management's~~Management’s Discussion and Analysis, herein.

Forward-Looking Statements: From time to time we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, assumptions of future events, future financial performance or growth and other statements that are not historical facts. These statements are ~~"forward-looking statements"~~“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,"~~“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:

~~the possibility that expected merger synergies will not be realized or will not be realized within the expected time period,~~

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

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

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

~~changes~~fluctuations in weather patterns,

changes in laws, regulations or regulatory policy,

changes in levels ~~and~~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 ~~2012~~2013 Annual Report on Form 10-K. This Quarterly Report on Form 10-Q and NU’s ~~2012~~2013 Annual Report on Form 10-K also

Table of Contents

describe material contingencies and critical accounting policies in the accompanyingManagement’s Discussion and Analysis of Financial Condition and Results of Operations andCombined Notes to Condensed Consolidated Financial Statements (Unaudited). We encourage you to review these items.

Financial Condition and Business Analysis

~~Merger with NSTAR:~~

On April 10, 2012, NU and NSTAR completed our merger. Unless otherwise noted, the results of NSTAR LLC and its subsidiaries, hereinafter referred to as "NSTAR," are included in NU’s financial position, results of operations and cash flows as of and for the three months ended March 31, 2013 throughout this~~Management's Discussion and Analysis of Financial Condition and Results of Operations~~.

Executive Summary

The ~~following~~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 ~~is for~~compares the three months ended March 31, ~~2013, compared~~2014 with the same period in ~~2012:~~2013:

We earned $236 million, or $0.74 per share, compared with $228.1 million, or $0.72 per share. Excluding integration costs, we earned $241.8 million, or $0.76 per share, compared with ~~$99.3 million, or $0.56 per share. Excluding merger related costs, we earned~~ $229.9 million, or $0.73 per ~~share, compared with $100.4 million, or $0.56 per~~ share. Improved earnings results ~~in 2013~~ were due primarily to ~~the inclusion of NSTAR,~~ higher retail electric and firm natural gas sales ~~due primarily to colder weather in the first quarter of 2013, as compared to the first quarter of 2012, higher transmission segment earnings~~ as a result of ~~increased investments in~~colder weather, partially offset by the ~~transmission infrastructure, lower overall operations and maintenance costs and~~absence of a favorable impact ~~of $13.6 million, or $0.04 per share,~~ from the resolution of a state income tax ~~audit.~~

~~The addition of NSTAR provided an earnings contribution of $67.5 million for~~audit in the first quarter of 2013. ~~Due to the timing~~

·The resolution of the ~~merger closing, April 10, 2012, NSTAR’s~~state income tax audit provided a $13.6 million, or $0.04 per share, benefit to our first quarter ~~2012 results are not reflected in NU’s first quarter 2012 results.~~2013 earnings, consisting of a $6.7 million benefit to NU parent, a $5.7 million benefit to our transmission segment, and a $1.2 million benefit to our electric distribution segment.

Our electric distribution segment, which includes generation, earned $112.2 million, or $0.35 per share, compared with $99.5 million, or $0.32 per ~~share, compared with $42~~share.

·Our transmission segment earned $74.9 million, or $0.24 per ~~share.~~

~~Our transmission segment earned~~share, compared with $79.9 million, or $0.25 per ~~share, compared with $46.3~~share. The decrease was due to the absence of the $5.7 million ~~or $0.26 per share.~~favorable impact from the resolution described above.

Our natural gas distribution segment earned $52.1 million, or $0.16 per share, compared with $43.3 million, or $0.14 per ~~share, compared with $14.7 million, or $0.08 per~~ share.

NU parent and other companies ~~earned $5.4~~had net losses of $3.2 million, or ~~$0.02~~$0.01 per share, compared with ~~net losses~~earnings of ~~$3.7~~$5.4 million, or $0.02 per share. Excluding ~~merger related~~integration costs, NU parent and other companies earned $2.6 million, or $0.01 per share, compared with $7.2 million, or $0.02 per ~~share, compared with net losses of $2.6 million, or $0.02 per~~ share.

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

~~On February 8, 2013, a blizzard caused damage~~The decrease was due to the ~~electric delivery systems~~absence of ~~CL&P and NSTAR Electric. Approximately 71,000 and 320,000~~the $6.7 million favorable impact from the resolution described above.

Regulatory Items:

·On March 12, 2014, the PURA issued a final decision that approved recovery of CL&P’s $365 million in storm restoration costs and ~~NSTAR Electric's distribution customers, respectively, were without power during or following~~ordered CL&P to capitalize approximately $18 million of the ~~blizzard. The blizzard resulted in estimated~~ deferred storm restoration costs as utility plant. PURA will allow recovery of ~~approximately $93 million. We believe~~ the ~~storm restoration costs meet the criteria for specific cost recovery~~$365 million with carrying charges in ~~each respective state and, as a result, we do not expect the blizzard to have a material impact on our results of operations.~~

~~In March 2013,~~ CL&P and NSTAR Electric filed a request with the PURA and DPU, respectively, seeking approval to recover storm restoration costs. CL&P requested approval to recover approximately $414 million of prudently incurred storm restoration costs, plus carrying costs, related to five major storms, all of which occurred in 2012 and 2011, in&P’s distribution rates over a six-year period beginning on December 1, 2014. ~~NSTAR~~

·Pursuant to an October 2013 request from the New Hampshire Legislative Oversight Committee on Electric ~~requested approval~~Utility Restructuring, staff of the NHPUC issued a report on April 1, 2014 that included a consultant’s analysis of the fair market value of PSNH generating assets and long-term power purchase contracts. The consultant’s analysis estimated the fair market value of PSNH’s generation assets to ~~recover approximately $35~~be $225 million as of December 31, 2013, compared to their net book value of $660 million, implying potential “stranded costs” in ~~prudently incurred storm restoration costs, plus carrying costs, related~~excess of $400 million. The NHPUC staff recommended that any further actions relating to ~~Tropical Storm Irene~~PSNH’s generating assets await a final decision in the Clean Air Project prudence proceeding, that existing laws regarding divestiture, energy service, and cost recovery be harmonized, and that ISO-NE provide input on the economic and reliability consequences of retirement of PSNH’s fossil generating plants. In the event of generation asset divestiture or retirement, both present law and the ~~October snowstorm~~PSNH Restructuring Settlement Agreement approved in ~~distribution rates over a five-year period beginning on January 1, 2014.~~2000 require that the NHPUC provide stranded cost recovery to PSNH.

Liquidity:

Cash and cash equivalents totaled ~~$60.8~~$89.2 million as of March 31, ~~2013,~~2014, compared with ~~$45.7~~$43.4 million as of December 31, ~~2012,~~2013, while ~~cash capital expenditures~~investments in property, plant and equipment totaled ~~$389~~$348.7 million ~~for~~in the first quarter of ~~2013,~~2014, compared with ~~$304.3~~$389 million ~~for~~in the first quarter of ~~2012.~~2013.

Cash flows provided by operating activities totaled ~~$410.6~~$493.8 million in the first quarter of ~~2013,~~2014, compared with ~~cash flows used in operating activities of $9.1~~$473.1 million in the first quarter of ~~2012 (amounts are net of RRB payments).~~2013. The improved operating cash flows were due primarily to the absence of cash disbursements for major storm restoration costs and a decrease in ~~storm restoration costs, the addition of NSTAR, the proceeds CYAPC~~Pension and ~~YAEC~~

~~received from the DOE~~PBOP Plan cash contributions, partially offset by an increase in income taxes paid in the first quarter of 2014, as compared to the first quarter of 2013, ~~a decrease in NUSCO Pension Plan cash contributions,~~ and the absence of costs recovered in rates related to the ~~February 2012 CL&P customer bill credits.~~RRBs that were fully amortized in the first half of 2013.

·39

Table of Contents

~~On January 15, 2013, CL&P~~

·In the first quarter of 2014, we issued $400 million of ~~2.5 percent first mortgage bonds that will mature~~new long-term debt consisting of $100 million by Yankee Gas on January ~~15, 2023. The proceeds, net of issuance costs,~~2, 2014 and $300 million by NSTAR Electric on March 7, 2014. These new issuances were used primarily to repay ~~CL&P’s revolving credit facility borrowings~~approximately $375 million of ~~$89 million and intercompany loans related~~existing long-term debt.

·On February 4, 2014, our Board of Trustees approved a common dividend payment of $0.3925 per share, payable on March 31, 2014 to ~~our commercial paper program borrowings~~shareholders of ~~$305.8 million.~~

record as of March 3, 2014. On May 1, ~~2013, PSNH redeemed at par approximately $109 million~~2014, our Board of ~~PCRBs, due~~Trustees approved a common dividend payment of $0.3925 per share, payable June 30, 2014 to ~~mature in 2021, with short-term debt.~~ shareholders of record as of May 30, 2014.

Overview

Consolidated: A summary of our earnings by business, which also reconciles the non-GAAP financial measures of consolidated non-GAAP earnings and EPS, as well as EPS by business, to the most directly comparable GAAP measures of consolidated Net Income Attributable to Controlling Interest and diluted EPS, for the first quarters of ~~2013~~2014 and ~~2012~~2013 is as follows:

For the Three Months Ended March 31,

2013⁽¹⁾

2012
(Millions of Dollars, Except Per Share Amounts)

Amount

Per Share

Amount

Per Share
Net Income Attributable to Controlling Interest (GAAP)
$
228.1

$
0.72

$
99.3

$
0.56

Regulated Companies
$
222.7

$
0.71

$
103.0

$
0.58
NU Parent and Other Companies

7.2

0.02

(2.6)

(0.02)
Non-GAAP Earnings

229.9

0.73

100.4

0.56
Merger Related Costs (after-tax)

(1.8)

(0.01)

(1.1)

-
Net Income Attributable to Controlling Interest (GAAP)
$
228.1

$
0.72

$
99.3

$
0.56

⁽¹⁾ ~~Results include the operations of NSTAR.~~

	For the Three Months Ended March 31,
	2014						2013
(Millions of Dollars, Except Per Share Amounts)	Amount			Per Share			Amount			Per Share
Net Income Attributable to Controlling Interest (GAAP)	$	236.0		$	0.74		$	228.1		$	0.72

Regulated Companies	$	239.2		$	0.75		$	222.7		$	0.71
NU Parent and Other Companies	2.6			0.01			7.2			0.02
Non-GAAP Earnings	241.8			0.76			229.9			0.73
Integration Costs (after-tax)	(5.8		)	(0.02		)	(1.8		)	(0.01		)
Net Income Attributable to Controlling Interest (GAAP)	$	236.0		$	0.74		$	228.1		$	0.72

Excluding the ~~impacts~~impact of ~~the merger related~~integration costs, our first quarter ~~2013~~2014 earnings increased by ~~$129.5~~$11.9 million, as compared to the first quarter ~~2012,~~of 2013, due primarily to ~~the inclusion of NSTAR,~~ higher retail electric and firm natural gas sales ~~due primarily to colder weather in the first quarter of 2013, as compared to the first quarter of 2012, higher transmission segment earnings~~ as a result of ~~increased investments in~~colder weather, partially offset by the ~~transmission infrastructure, lower overall operations and maintenance costs, and~~absence of a favorable impact ~~of $13.6 million, or $0.04 per share,~~ from the resolution of a state income tax ~~audit. On an earnings per share basis,~~audit in the first quarter of 2013. The resolution of the state income tax audit provided a $13.6 million, or $0.04 per share, benefit to our first quarter 2013 NSTAR earnings contribution of $67.5 million ($67.8 million in non-GAAP earnings) was partially offset by the issuance of approximately 136 million common shares to close the merger. Partially offsetting these favorable earnings impacts were higher depreciation and property tax expense.earnings.

Regulated Companies: Our Regulated companies consist of the electric distribution, transmission, and natural gas distribution ~~and transmission~~ segments. Generation activities of PSNH and WMECO are included in our electric distribution segment. A summary of our segment earnings for the first quarters of ~~2013~~2014 and ~~2012~~2013 is as follows:

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

2013⁽¹⁾

2012
Electric Distribution

$
99.5

$
42.0
Transmission

79.9

46.3
Natural Gas Distribution

43.3

14.7
Net Income - Regulated Companies

$
222.7

$
103.0

⁽¹⁾ ~~Results include the operations of NSTAR.~~

	For the Three Months Ended March 31,
(Millions of Dollars)	2014		2013
Electric Distribution	$	112.2	$	99.5
Transmission	74.9		79.9
Natural Gas Distribution	52.1		43.3
Net Income - Regulated Companies	$	239.2	$	222.7

~~The higher~~Our electric distribution segment earnings increased $12.7 million in the first quarter ~~2013 transmission segment earnings,~~of 2014, as compared to the first quarter of ~~2012,~~2013, due primarily to higher retail electric sales as a result of colder weather. The 2014 results were also favorably impacted by a PSNH rate increase effective July 1, 2013 as a result of the 2010 distribution rate case settlement. Partially offsetting these favorable impacts were higher depreciation and property tax expense.

Our transmission segment earnings decreased in the first quarter of 2014, as compared to the first quarter of 2013, due primarily to the ~~inclusion~~absence of the $17.8 million NSTAR Electric transmission business’ earnings, increased investments in the transmission infrastructure, including GSRP, which is under construction in western Massachusetts and northern Connecticut, and the favorable impact from the resolution of athe state income tax ~~audit.~~

~~The higher~~audit in the first quarter of 2013, which provided a $5.7 million benefit to our first quarter 2013 ~~electric~~transmission segment earnings, 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 in the first quarter of 2014, as compared to the first quarter of ~~2012, were~~2013, due primarily to the inclusion of the $29.9 million NSTAR Electric distribution business’ earnings, higher retail electric sales due primarily to colder weather in the first quarter of 2013, as compared to the first quarter of 2012, and lower overall operations and maintenance costs. In addition, we had a favorable impact resulting from the PSNH 2010 distribution rate case decision. As a result of the decision, the PSNH rates increased effective July 1, 2012. Partially offsetting these favorable earnings impacts were higher depreciation and property tax expense. For further information regarding NSTAR Electric’s earnings, see "Results of Operations – NSTAR Electric Company and Subsidiaries – Earnings Summary" in this~~Management's Discussion and Analysis of Financial Condition and Results of Operations.~~

The higher first quarter 2013 natural gas distribution segment earnings, as compared to the first quarter of 2012, were due primarily to the inclusion of the $19.3 million NSTAR Gas business’ earnings, higher firm natural gas sales ~~due primarily to~~as a result of colder weather, inas well as the ~~first quarter~~addition of ~~2013, as compared to the first quarter~~new natural gas heating customers.

Table of ~~2012, the favorable impact of the Yankee Gas 2011 rate case decision resulting in the~~Contents

~~additional increase to annualized rates effective July 1, 2012, and lower interest expense, partially offset by higher depreciation expense and property tax expense.~~

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

	For the Three Months Ended March 31, 2014 Compared to 2013
	Sales (GWh)		Percentage
NU – Electric	2014	2013	Increase
Residential	6,139	5,803	5.8	%
Commercial (1)	6,866	6,695	2.6	%
Industrial	1,343	1,298	3.4	%
Total	14,348	13,796	4.0	%

	For the Three Months Ended March 31, 2014 Compared to 2013
	CL&P		NSTAR Electric		PSNH		WMECO
Electric	Percentage Increase		Percentage Increase		Percentage Increase		Percentage Increase/ (Decrease)
Residential	6.9	%	4.1	%	5.8	%	5.7	%
Commercial (1)	2.3	%	2.6	%	2.3	%	4.2	%
Industrial	4.2	%	3.5	%	4.8	%	(2.4	)%
Total	4.7	%	3.2	%	4.2	%	3.8	%

(1)Commercial retail electric GWh sales include streetlighting and railroad retail sales.

A summary of our firm natural gas sales in million cubic feet and percentage changes, as well as percentage changes in Yankee Gas and NSTAR ~~Gas’ sales in million cubic feet, for the first quarter of 2013, as compared to the first quarter 2012,~~Gas, is as follows:

				For the Three Months Ended March 31, 2014 Compared to 2013
	For the Three Months Ended March 31, 2013 Compared to 2012			Sales (million cubic feet)		Percentage
	Sales (GWh)		Percentage
NU – Electric	2013⁽¹⁾	2012	Increase
NU - Firm Natural Gas				2014	2013	Increase
Residential	5,803	3,787	53.2%	19,812	17,015	16.4	%
Commercial	6,570	3,381	94.3%	19,627	16,771	17.0	%
Industrial	1,298	1,015	28.0%	7,478	6,829	9.5	%
Other	125	88	42.5%
Total	13,796	8,271	66.8%	46,917	40,615	15.5	%
Total, Net of Special Contracts (1)				45,550	39,422	15.5	%

					For the Three Months Ended March 31, 2014 Compared to 2013
	For the Three Months Ended March 31, 2013 Compared to 2012				Sales (million cubic feet)
	CL&P	NSTAR Electric⁽²⁾	PSNH	WMECO	Yankee Gas		NSTAR Gas
Electric	Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)
					Percentage		Percentage
Firm Natural Gas					Increase		Increase
Residential	9.2 %	4.1 %	4.3 %	5.6 %	21.8	%	12.9	%
Commercial	2.0 %	1.9 %	2.2 %	(1.0)%	21.0	%	13.6	%
Industrial	(4.6)%	(5.2)%	0.6 %	(0.8)%	10.2	%	7.7	%
Other	0.6 %	(10.1)%	(2.7)%	22.6 %
Total	4.7 %	2.0 %	2.8 %	2.1 %	18.6	%	12.7	%
Total, Net of Special Contracts (1)					18.9	%

⁽¹⁾

~~Results include retail electric sales of NSTAR Electric.~~

⁽²⁾

~~Results for NSTAR Electric include its standalone first quarter March 31, 2013 retail electric sales, as compared to 2012.~~

For the Three Months Ended
March 31, 2013 Compared to 2012

Sales (million cubic feet)
NU – Firm Natural Gas

2013⁽¹⁾

2012
Residential

17,015

5,375
Commercial

16,771

6,382
Industrial

6,829

5,062
Total

40,615

16,819
Total, Net of Special Contracts⁽²⁾

39,422

14,744

For the Three Months Ended
March 31, 2013 Compared to 2012

Yankee Gas

NSTAR Gas⁽³⁾
Firm Natural Gas

Percentage
Increase/(Decrease)

Percentage Increase
Residential

25.9 %

22.9%
Commercial

21.4 %

16.3%
Industrial

(4.4)%

29.3%
Total

15.1 %

20.6%
Total, Net of Special Contracts⁽²⁾

23.2 %

⁽¹⁾

~~Results include firm natural gas sales of NSTAR Gas.~~

⁽²⁾

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.

⁽³⁾

~~NSTAR Gas’ sales data for the three months ended March 31, 2013 compared to 2012 has been provided for comparative purposes only.~~

Weather, fluctuations in ~~fuel~~energy supply costs, conservation measures (including company-sponsored energy efficiency programs), and economic conditions affect ~~sales to our customers.~~customer energy usage. Industrial sales are less sensitive to temperature variations than residential and commercial sales. ~~Weather~~In our service territories, weather impacts electric sales ~~primarily~~ during the summer and electric and natural gas sales during the winter ~~in our service territories~~ (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, particularly when weather patterns experienced are consistently colder or warmer.~~occur. In addition, our electric and natural gas businesses ~~are sensitive to variations in daily weather, are highly influenced by New England’s seasonal weather variations, and~~ are susceptible to damage from major storms and other natural events and disasters that could adversely affect our ability to provide energy.

Our first quarter 2014 consolidated retail electric sales, consisting of the retail electric sales of CL&P, NSTAR Electric, PSNH, and ~~firm natural gas sales~~WMECO, were higher, ~~in the first quarter of 2013,~~ as compared to the first quarter of ~~2012, due to the inclusion of NSTAR Electric and NSTAR Gas sales.~~

~~Actual retail electric sales for CL&P, NSTAR Electric, PSNH, and WMECO increased in the first quarter of~~ 2013, ~~as compared to 2012,~~ due primarily to ~~the~~ colder ~~weather in the first~~weather. First quarter ~~of 2013, as compared to the first quarter of 2012. In the first quarter of 2013,~~2014 heating degree days were 2116 percent higher in Connecticut and western Massachusetts, ~~22 percenthigher~~12 percent higher in the Boston metropolitan area, and 15 percent higher in New Hampshire, as compared to ~~2012. On a weather-normalized basis~~the first quarter of 2013. Weather-normalized retail electric sales (based on 30-year average temperatures)~~, the average NU combined consolidated total retail electric sales was relatively unchanged~~ increased 1.3 percent in the first quarter of ~~2013,~~2014, as compared to ~~2012, assuming NSTAR Electric had been part~~the first quarter of ~~the NU combined electric distribution system for all periods under consideration.~~ 2013, reflecting a steady improvement in economic conditions across our service territory.

Table of Contents

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

Our firm natural gas sales are subject to many of the same influences as our retail electric ~~sales, but~~sales. In addition, they have benefitted from ~~lower~~historically favorable natural gas prices and customer growth across ~~all three customer classes. In the~~both operating companies. Our first quarter 2014 consolidated firm natural gas sales, consisting of ~~2013, excluding~~ the ~~impact~~firm natural gas sales of Yankee Gas and NSTAR Gas, ~~sales, actual sales increased,~~were higher, as compared to the first quarter of ~~2012,~~2013, due primarily to ~~the~~ colder ~~weather in the~~weather. The first quarter ~~of 2013, as compared to the first quarter of 2012. On a~~2014 weather-normalized basis, Yankee Gas’ first quarter 2013 sales also increased due primarily to customer growth, lower cost of natural gas when compared to the cost of other energy sources, the migration of interruptible customers switching to firm service rates, and the addition of gas-fired distributed generation in Yankee Gas’ service territory.

~~On a weather-normalized basis, the average~~ NU ~~combined~~ consolidated total firm natural gas sales increased ~~2.6 percentin the first quarter of 2013,~~3.6 percent, as compared to the ~~first quarter of 2012, assuming NSTAR Gas had been part of the NU combined natural gas distribution system for all periods under consideration.~~same period in 2013, due primarily to residential and commercial customer growth.

NU Parent and Other Companies: NU parent and other companies, ~~(which~~which includes our competitive businesses, ~~held by NU Enterprises and, for~~had net losses of $3.2 million in the first quarter of ~~2013, NSTAR LLC) earned~~2014, compared with earnings of $5.4 million in the first quarter of ~~2013, compared with net losses of $3.7 million in the first quarter of 2012.~~2013. Excluding the impact of ~~the merger related~~integration costs, NU parent and other companies earned $2.6 million in the first quarter of 2014, compared with $7.2 million in the first quarter of ~~2013, compared with net losses of $2.6 million. Improved results were~~2013. The decrease in earnings was due ~~primarily to lower interest expense, a lower effective tax rate and the inclusion of NSTAR Communications.~~

~~Major Storm Restoration Costs:~~ A storm must meet certain criteria specific to each state and utility company to be declared a major storm. Once a storm is declared major, all qualifying expenses incurred during storm restoration efforts, if deemed prudent, are deferred and recovered from customers in future periods. In Connecticut, qualifying storm restoration costs must exceed $5 million for a storm to be declared a major storm. In Massachusetts, qualifying storm restoration costs must exceed $1 million for NSTAR Electric and $300,000 for WMECO and an emergency response plan must be initiated for a storm to be declared a major storm. In New Hampshire, (1) at least 10 percent of customers must be without power with at least 200 concurrent locations requiring repairs (trouble spots), or (2) at least 300 concurrent trouble spots must be reported for a storm to be declared a major storm.

~~On February 8, 2013, a blizzard caused damage~~ to the ~~electric delivery systems~~absence of ~~CL&P and NSTAR Electric. Approximately 71,000 and 320,000~~the favorable impact from the resolution of ~~CL&P’s and NSTAR Electric's distribution customers, respectively, were without power during or following~~ the ~~blizzard. The blizzard resulted~~state income tax audit in ~~estimated deferred storm restoration costs~~the first quarter of ~~approximately $13~~2013, which provided a $6.7 million at CL&P and approximately $80 million at NSTAR Electric. We believe the storm restoration costs meet the criteria for specific cost recovery in Connecticut and Massachusetts and, as a result, we do not expect the blizzardbenefit to have a material impact on CL&P’s or NSTAR Electric’s results of operations. CL&P and NSTAR Electric will seek recovery of these deferred storm restoration costs through their applicable regulatory recovery process.first quarter 2013 NU parent earnings.

Liquidity

Consolidated: Cash and cash equivalents totaled ~~$60.8~~$89.2 million as of March 31, ~~2013,~~2014, compared with ~~$45.7~~$43.4 million as of December 31, ~~2012.~~ 2013.

On January ~~15, 2013, CL&P~~2, 2014, Yankee Gas issued ~~$400~~$100 million of ~~2.5~~4.82 percent ~~first mortgage bonds that will~~Series L First Mortgage Bonds, due to mature ~~on January 15, 2023.~~in 2044. The proceeds, net of issuance costs, were used to repay ~~CL&P’s revolving credit facility borrowings of $89~~the $75 million 4.80 percent Series G First Mortgage Bonds that matured on January 1, 2014 and ~~intercompany loans related~~ to ~~our commercial paper program borrowings of $305.8 million.~~repay $25 million in short-term borrowings.

On ~~May 1, 2013, PSNH redeemed at par approximately $109~~March 7, 2014, NSTAR Electric issued $300 million of ~~the 2001 Series C PCRBs that were~~4.40 percent debentures, due to mature in ~~2021 with~~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.

NU parent, CL&P, PSNH, WMECO, NSTAR Gas and Yankee Gas are parties to a joint five-year $1.45 billion revolving credit facility due to expire on September 6, 2018. The revolving credit facility is to be used primarily to backstop the $1.45 billion commercial paper program at NU. The commercial paper program allows NU parent to issue commercial paper as a form of short-term debt. As ~~a result, the PCRBs were recorded as Long-Term Debt - Current Portion.~~

of March 31, 2014 and December 31, 2013, NU CL&P, NSTAR Electric, PSNH and WMECO use their available capital resources to fund their respective construction expenditures, meet debt requirements, pay 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 operate in an environment where recovery of its electric and natural gas distribution construction expenditures takes place over an extended period of time. 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 NU’s current liabilities exceeding current assets byhad approximately

~~$1.7 billion, $231 million, $226 million, $34~~ $818.5 million and ~~$48~~$1.01 billion, respectively, in short-term borrowings outstanding under the NU parent commercial paper program, leaving $631.5 million ~~at NU, CL&P, NSTAR Electric, PSNH~~,and ~~WMECO, respectively,~~$435.5 million of available borrowing capacity as of March 31, ~~2013.~~

2014 and December 31, 2013, respectively. The weighted-average interest rate on these borrowings as of March 31, 2014 and December 31, 2013 was 0.23 percent and 0.24 percent, respectively, which is generally based on money market rates. As of March 31, 2014, there were intercompany loans from NU of $351.6 million to CL&P, $39.9 million to PSNH and $37.4 million to WMECO. As of December 31, 2013, ~~approximately $914~~there were intercompany loans from NU of $287.3 million to CL&P and $86.5 million to PSNH.

NSTAR Electric has a five-year $450 million revolving credit facility due to expire on September 6, 2018. This facility serves to backstop NSTAR Electric’s existing $450 million commercial paper program. As of March 31, 2014, NSTAR Electric had no borrowings outstanding under its commercial paper program. As of December 31, 2013, NSTAR Electric had $103.5 million in short-term borrowings outstanding under its commercial paper program, leaving $346.5 million of ~~NU's current liabilities relates to long-term debt that will be paid in the next 12 months, consisting~~available borrowing capacity. The weighted-average interest rate on these borrowings as of $550 million for NU parent, $125 million for CL&P, $109 million for PSNH, $75 million for Yankee Gas, and $55 million for WMECO. 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, as deemed appropriate given our capital requirements and maintenance of our credit rating and profile. Management expects the future operating cash flows of NU and its subsidiaries, along with the access to financial markets, will be sufficient to meet any future operating requirements and capital investment forecasted opportunities.December 31, 2013 was 0.13 percent, which is generally based on money market rates.

Cash flows provided by operating activities ~~in the first quarter of 2013~~ totaled ~~$410.6 million, compared with cash flows used in operating activities of $9.1~~$493.8 million in the first quarter of ~~2012 (all amounts are net~~2014, compared with $473.1 million in the first quarter of ~~RRB payments, which are included in financing activities on the accompanying consolidated statements of cash flows).~~2013. The improved operating cash flows were due primarily to the absence inof cash disbursements for major storm restoration costs and the ~~first quarter~~decrease of ~~2013 of approximately $153~~$40.3 million in Pension and PBOP Plan cash disbursements associated with Tropical Storm Irene and the October snowstorm, the addition of NSTAR, which contributed $138.1 million of operating cash flows (net of RRB payments) in the first quarter of 2013, as well as the $77.9 million in proceeds CYAPC and YAEC received from the DOE in the first quarter of 2013 that were subsequently invested in marketable securities and are expected to benefit CL&P, NSTAR Electric, PSNH and WMECO customers. Also contributing to the improved operating cash flows was a reduction of NUSCO Pension Plan contributions, of $56.9 million in the first quarter of 2013, as compared to the first quarter of 2012, the absence in the first quarter of 2013 of approximately $27 million in 2012 CL&P customer bill credits and the favorable cash flow impacts associated with transmission regulatory tracking mechanisms of $16.1 million. Partially offsetting these favorable impacts was a $19.6 millionpartially offset by an increase in income taxes paid in the first quarter of ~~2013,~~2014 ($82.6 million), as compared to the first quarter of ~~2012.~~ 2013 ($22.2 million), and the absence of costs recovered in rates related to the RRBs that were fully amortized in the first half of 2013.

~~A summary~~On March 28, 2014, CYAPC and YAEC received payment of $163.3 million of the ~~current~~DOE Phase II Damages proceeds. It is anticipated that in the second quarter of 2014, the Yankee Companies will complete the FERC review process and return these amounts to the member companies, including CL&P, NSTAR Electric, PSNH, and WMECO, for the benefit of their respective customers. As a result of the consolidation of CYAPC and YAEC, the cash received was included in Other Long-Term Assets on the NU consolidated balance sheet pending refund as of March 31, 2014 and in Proceeds from DOE Damages Claim with an offset in Deferred DOE Proceeds on the NU consolidated statement of cash flows for the three months ended March 31, 2014. These proceeds had no impact on NU’s earnings or net cash flows provided by operating activities for the three months ended March 31, 2014.

On January 31, 2014, Moody’s upgraded corporate credit and securities ratings of NU, CL&P and PSNH by one level and WMECO by two-levels. On April 7, 2014, Fitch affirmed the corporate credit ratings and ~~outlooks by Moody's,~~outlook of NU, CL&P, NSTAR Electric, PSNH, WMECO and NSTAR Gas. On April 25, 2014, S&P affirmed the corporate credit ratings and ~~Fitch for senior unsecured debt~~revised the outlooks to positive from stable of NU, ~~parent,~~CL&P, NSTAR Electric, PSNH, WMECO, Yankee Gas and ~~WMECO and senior secured debt~~NSTAR Gas.

Table of ~~CL&P and PSNH is as follows:~~Contents

~~Moody's~~

~~S&P~~

~~Fitch~~

~~Current~~

~~Outlook~~

~~Current~~

~~Outlook~~

~~Current~~

~~Outlook~~

~~NU Parent~~

~~Baa2~~

~~Stable~~

~~BBB+~~

~~Stable~~

~~BBB+~~

~~Stable~~

~~CL&P~~

~~Stable~~

~~NSTAR Electric~~

~~Stable~~

A-

~~Stable~~

A+

~~Stable~~

~~PSNH~~

~~Stable~~

~~WMECO~~

~~Baa2~~

~~Stable~~

A-

~~Stable~~

A-

~~Stable~~

In the first quarter of 2014, we had cash dividends on common shares of $118.5 million, compared with $116.4 million in the first quarter of 2013. On February ~~14, 2013, S&P revised its criteria for rating utility first mortgage bonds, resulting in one-level upgrades of CL&P and PSNH first mortgage bonds by S&P.~~

~~On February 5, 2013,~~4, 2014, our Board of Trustees approved a common dividend payment of ~~$0.3675~~$0.3925 per share, payable on March ~~28, 2013~~31, 2014 to shareholders of record as of March 1,3, 2014. The dividend represented an increase of 6.8 percent over the dividend paid in December 2013. On ~~April 2, 2013,~~May 1, 2014, our Board of Trustees approved a common dividend payment of ~~$0.3675~~$0.3925 per share, payable June ~~28, 2013~~30, 2014 to shareholders of record as of May ~~31, 2013.~~30, 2014.

In the first quarter of ~~2013,~~2014, CL&P, NSTAR ~~LLC,~~Electric, PSNH, and WMECO paid ~~$38~~$42.8 million, $8$253 million, ~~$17~~$16.5 million, and ~~$10~~$49 million, respectively, in common dividends to NU parent.

~~The NSTAR Electric RRBs were fully amortized~~Investments in ~~the first quarter of 2013. The PSNH~~Property, Plant and ~~WMECO RRBs are scheduled to fully amortize in the second quarter of 2013.~~

~~Cash capital expenditures included~~Equipment on the accompanying ~~consolidated~~ statements of cash flows ~~and described in this "Liquidity" section~~ 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. ~~A summary of our cash capital expenditures by company for the first quarters of 2013 and 2012 is as follows:~~

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

2013⁽¹⁾

2012
CL&P

$
89.4

$
108.8
NSTAR Electric

107.6

N/A
PSNH

65.0

67.1
WMECO

66.3

85.0
Natural Gas

31.2

20.4
NPT

14.9

5.7
Other

14.6

17.3
Total

$
389.0

$
304.3

⁽¹⁾

~~Results include cash capital expenditures of NSTAR.~~

~~The increase in our cash capital expenditures was the result of the addition of NSTAR’s capital expenditures for~~In the first quarter of ~~2013, as compared to the first quarter of 2012.~~2014, investments for NU, CL&P, NSTAR Electric, PSNH, and WMECO were $348.7 million, $108 million, $95 million, $61.9 million, and $30.3 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 $277.9 million in the first quarter of 2014, compared with $299.8 million in the first quarter of ~~2013, compared with $306.5 million in the first quarter of 2012.~~2013. These amounts included ~~$5.4~~$5.9 million and ~~$11.6~~$5.4 million in the first quarters of ~~2013~~2014 and ~~2012,~~2013, respectively, related to our corporate service companies, NUSCO and RRR.

Transmission Business:Overall, transmission business capital expenditures ~~increased~~decreased by ~~$4.8~~$53.3 million in the first quarter of ~~2013,~~2014, as compared to the first quarter of 2012. The first quarter 2013 results reflect the addition of NSTAR Electric's capital expenditures and an increase at NPT, offset by a decrease at WMECO related to the construction of GSRP nearing completion.2013. A summary of transmission capital expenditures by company for the three months ended March 31, ~~2013~~2014 and ~~2012~~2013 is as follows:


	For the Three Months Ended March 31,				For the Three Months Ended March 31,
(Millions of Dollars)	2013⁽¹⁾		2012		2014		2013
CL&P	$	44.0	$	40.2	$	36.2	$	44.0
NSTAR Electric		49.3		N/A	12.4		49.3
PSNH		14.6		15.1	16.7		14.6
WMECO		17.2		74.6	16.3		17.2
NPT		16.5		6.9	6.7		16.5
Total Transmission Segment	$	141.6	$	136.8	$	88.3	$	141.6

⁽¹⁾

~~Results include transmission capital expenditures of NSTAR Electric.~~

NEEWS: GSRP, ~~a project that involves the construction of 115 kV and 345 kV overhead lines by CL&P and WMECO from Ludlow, Massachusetts to Bloomfield, Connecticut, is~~ the first, largest and most complicated project within the NEEWS family of ~~projects. The $718 million project is expected to be~~projects was fully ~~placed in service in late~~energized on November 20, 2013. ~~If all events surrounding completion of the project continue at their current state, the total cost could be approximately five percent lower.~~ As of March 31, ~~2013, the project was approximately 95 percent complete~~2014, CL&P and ~~we had~~WMECO have placed ~~$440~~$631.5 million in ~~service.~~ service with minimal remaining close-out activities continuing throughout the first half of 2014.

The Interstate Reliability Project, which includes CL&P’s construction of an approximately 40-mile, 345 kV overhead line from Lebanon, Connecticut to the Connecticut-Rhode Island border in Thompson, Connecticut where it will connect to transmission enhancements being constructed by National Grid, is ~~our~~the second major NEEWS project. ~~All siting applications~~The Connecticut and Rhode Island portions of the project have been ~~filed~~approved by ~~CL&P and National Grid. On~~their respective siting boards. On January ~~2, 2013,~~30, 2014, the ~~Connecticut Siting Council~~Massachusetts EFSB voted unanimously to draft a tentative opinion approving the MA component of the project; a siting approval decision in Massachusetts is expected in the second quarter of 2014. In the first quarter of 2014, the Army Corps of Engineers issued ~~a final decision and order approving~~its permit on the project, which enabled construction on the Connecticut portion of the ~~project. Decisions in Rhode Island~~project to begin. NU’s portion of the cost is estimated to be $218 million and ~~Massachusetts are expected between~~ the ~~end of 2013 and early 2014. The $218 million~~ project is expected to be placed in service in late 2015.

The Greater Hartford Central Connecticut Study (GHCC), which includes the reassessment of the Central Connecticut Reliability Project, continues to make progress. The final need results, which were presented to the ISO-NE Planning Advisory Committee in November 2013, showed existing and worsening severe regional and local thermal overloads and voltage violations within and across each of the four study areas. ISO-NE is expected to confirm the preferred transmission solutions in the summer of 2014, which are likely to include many 115 kV upgrades. We continue to expect that the specific future projects being identified to address these reliability concerns will cost approximately $300 million and that the project will be placed in service in 2017.

Included as part of NEEWS are associated reliability related projects, ~~approximately $72~~$90.5 million of which have been placed in ~~service and approximately $24~~service. As of March 31, 2014, the remaining construction on the associated reliability related projects totaled $2.9 million, of which ~~are in various phases of construction and will continue~~is scheduled to ~~go into service through 2013.~~ be completed by mid-2014.

Through March 31, ~~2013,~~2014, CL&P and WMECO ~~had~~ capitalized ~~$225~~$259 million and ~~$531~~$571.1 million, respectively, in costs associated with NEEWS, of which ~~$13~~$6.2 million and ~~$12.9~~$4.1 million, respectively, were capitalized in the first quarter of ~~2013.~~ 2014.

~~Greater Hartford Central Connecticut Project (GHCC):~~ In August 2012, ISO-NE presented its preliminary needs analysis for the GHCC to the ISO-NE Planning Advisory Committee. The results showed severe thermal overloads and voltage violations in each of the four study areas now and in the near future. A combination of 345 kV and 115 kV transmission solutions are being considered to address these reliability concerns and a set of preferred solutions are expected to be identified by ISO-NE in late 2013 or early 2014. We included approximately $300 million in our five-year capital program for future projects being identified to address these reliability concerns, which have recently been confirmed by ISO-NE.

~~Cape Cod Reliability Projects:~~ Transmission projects serving Cape Cod in the Southeastern Massachusetts (SEMA) reliability region consist of an expansion and upgrade of NSTAR Electric's existing transmission infrastructure including construction of a new 345 kV transmission line that will cross the Cape Cod Canal and associated 115 kV upgrades in the center of Cape Cod (Lower SEMA Transmission Project) and related 115 kV projects (Mid-Cape Project). All regulatory licensing and permitting is complete for the Lower SEMA Transmission Project and construction commenced in September 2012. The 345 kV line is expected to be energized by mid-2013 and the 115 kV line upgrades are expected to be completed in late 2013. The Mid-Cape Project is scheduled to be completed in 2017. The total estimated construction cost for the Cape Cod projects is approximately $150 million.

Northern Pass: Northern Pass is ~~NPT's~~NU’s planned HVDC transmission line from the Québec-New Hampshire border to Franklin, New Hampshire and an associated alternating current radial transmission line between Franklin and Deerfield, New Hampshire. Northern Pass will interconnect at the Québec-New Hampshire border with a planned HQ HVDC transmission line. ~~We estimate the costs~~NPT received ISO-NE approval under Section I.3.9 of the ISO tariff in 2013. By approving the project’s Section I.3.9 application, ISO-NE determined that Northern Pass can reliably interconnect with the New England grid with no significant adverse effect on the reliability or operating characteristics of the regional energy grid and its participants. The $1.4 billion project is subject to comprehensive federal and state public permitting processes and is expected to be operational in the second half of 2017. The DOE continues to work on the draft Environmental Impact Statement (EIS) for Northern Pass. This includes a review of both the recommended route and various

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alternative routes. We expect the DOE to issue the draft EIS in late 2014. Once it is published, DOE will commence a process of receiving written and verbal comments on the draft EIS and we expect the DOE to issue a final EIS in the second half of 2015. We expect to file the state permit application in January 2015 after the DOE’s draft EIS is received.

Greater Boston Reliability and Boston Network Improvements: As a result of continued analysis of the transmission ~~project will~~needs to enhance system reliability and improve capacity in eastern Massachusetts, NSTAR Electric and PSNH expect to implement a series of new transmission initiatives over the next five years. We expect ISO-NE to select preferred solutions in the first half of 2014. We expect projected costs to be approximately ~~$1.2 billion (including capitalized AFUDC) and we believe the project will be completed in mid-2017.~~ $480 million for these new initiatives.

Distribution Business: A summary of distribution capital expenditures by company for the first quarters of ~~2013~~2014 and ~~2012~~2013 is as follows:


	For the Three Months Ended March 31,				For the Three Months Ended March 31,
(Millions of Dollars)	2013⁽¹⁾		2012⁽²⁾		2014		2013
CL&P:
Basic Business	$	13.2	$	23.3	$	10.7	$	13.2
Aging Infrastructure		29.0		49.0	34.3		29.0
Load Growth		17.0		24.8	17.3		17.0
Total CL&P		59.2		97.1	62.3		59.2
NSTAR Electric:
Basic Business		15.6		N/A	29.6		15.6
Aging Infrastructure		27.3		N/A	22.9		27.3
Load Growth		1.9		N/A	6.5		1.9
Total NSTAR Electric		44.8		N/A	59.0		44.8
PSNH:
Basic Business		3.8		5.3	5.8		3.8
Aging Infrastructure		7.8		9.1	12.5		7.8
Load Growth		4.6		4.2	6.1		4.6
Total PSNH		16.2		18.6	24.4		16.2
WMECO:
Basic Business		0.5		3.9	1.5		0.5
Aging Infrastructure		4.3		3.4	3.3		4.3
Load Growth		1.5		2.2	1.4		1.5
Total WMECO		6.3		9.5	6.2		6.3
Total - Electric Distribution (excluding Generation)		126.5		125.2	151.9		126.5
PSNH Generation					2.5		0.7
WMECO Generation					4.1		0.1
Total - Natural Gas		25.5		16.3	25.2		25.5
Other Distribution		-		0.3
Total Electric and Natural Gas		152.0		141.8
PSNH Generation:
Clean Air Project		0.2		13.4
Other		0.5		2.8
Total PSNH Generation		0.7		16.2
WMECO Generation		0.1		0.1
Total Distribution Segment	$	152.8	$	158.1
Total Electric and Natural Gas Distribution Segment					$	183.7	$	152.8

⁽¹⁾

~~Includes the electric and natural gas distribution capital expenditures of NSTAR.~~

⁽²⁾

~~The prior period amounts have been reclassified to conform to current period presentation.~~

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, ~~plant~~distribution substations, underground cable replacement, and equipment failures. Load growth includes requests for new business and capacity additions on distribution lines and substation additions and expansions.

~~CL&P System Resiliency Plan:~~ On January 16, 2013, PURA approved the $300 million plan CL&P filed to improve the resiliency of its electric distribution system. The plan includes vegetation management (both enhanced tree trimming and trimming on a shorter cycle), structural hardening (strengthening field structures through upgrades to the current structure design and material standards as well as upgrades to the poles and conductors), and electrical hardening (upgrading electrical distribution conductors and protective devices on overhead circuits). CL&P expects to complete the plan in five years in two separate phases. The estimated cost of Phase 1 of the plan, which will be primarily focused on vegetation management, is $32 million in 2013 and $53 million in 2014. The estimated cost of Phase 2 of the plan is the remaining $215 million over the period from 2015 through 2017.

~~FERC Regulatory Issues~~

~~FERC Base ROE Complaint:~~ On September 30, 2011, several New England state attorneys general, state regulatory commissions, consumer advocates and other parties filed a joint complaint with the FERC under Sections 206 and 306 of the Federal Power Act alleging that the base ROE used in calculating formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by New England transmission owners, including CL&P, NSTAR Electric, PSNH and WMECO, is unjust and unreasonable. The complainants asserted that the current 11.14 percent rate, which became effective in 2006, is excessive due to changes in the capital markets and are seeking an order to reduce the rate, which would be effective October 1, 2011. In response, the New England transmission owners filed testimony and analysis based on standard FERC methodology and precedent, demonstrating that the base ROE of 11.14 percent remained just and reasonable. The FERC set the case for trial before a FERC administrative law judge after settlement negotiations were unsuccessful in August 2012.

As part of the pre-trial process, on April 17, 2013, the complainants, the Massachusetts municipal electric utilities (late intervenors to the case), and the FERC trial staff updated their respective ROE analyses, which demonstrated a base ROE of approximately 8.9 percent. The New England transmission owners also filed an updated analysis, including a supplement on April 26, 2013, that

continues to demonstrate that the current ROE of 11.14 percent remains within an updated range of reasonableness of 7.3 percent to 13.2 percent. Hearings on this complaint are scheduled to commence on May 6, 2013 and the trial judge’s recommended decision is due in September 2013. A decision from FERC commissioners is expected in 2014. Refunds to customers, if any, as a result of a reduction in the NU transmission companies’ base ROE would be for the period October 1, 2011 through December 31, 2012.

On December 27, 2012, several additional parties filed a separate complaint concerning the New England transmission owners' base ROE with the FERC. This new complaint seeks to reduce the New England transmission owners’ base ROE effective January 1, 2013, effectively extending the refund period for an additional 15 months, and to consolidate this new complaint with the joint complaint filed on September 30, 2011. The New England transmission owners have asked the FERC to reject this new complaint. The FERC has not yet acted on this request.

As of March 31, 2013, CL&P, NSTAR Electric, PSNH, and WMECO had approximately $2.1 billion of aggregate shareholder equity invested in their transmission facilities. As a result, each 10 basis point change in the authorized base ROE would change annual consolidated earnings by an approximate $2.1 million. We cannot at this time predict the ultimate outcome of this proceeding or the estimated impact on CL&P’s, NSTAR Electric’s, PSNH’s, or WMECO’s respective financial position, results of operations or cash flows.

Regulatory Developments and Rate Matters

The Regulated ~~companies'~~companies’ distribution rates are set by their respective state regulatory commissions, and their tariffs include mechanisms for periodically adjusting their rates. Other than as described below, for the first quarter of ~~2013,~~2014, changes made to the Regulated companies’ rates did not have a material impact on their earnings, financial position, or cash flows. For further information, see ~~"Financial~~“Financial Condition and Business Analysis –— Regulatory Developments and Rate ~~Matters"~~Matters” included in Item 7, "“~~Management's~~Management’s Discussion and Analysis of Financial Condition and Results of Operations,"” of the NU ~~2012~~2013 Annual Report on Form 10-K.

~~Major Storms:~~Connecticut:

~~2013, 2012 and 2011 Major Storms:~~ ~~In 2012 and 2011,~~ CL&P ~~NSTAR Electric, PSNH and WMECO each experienced significant storms that impacted their service territories, including Tropical~~2014 Storm ~~Irene, the October snowstorm, and Storm Sandy.~~

On February 8, 2013, a blizzard caused damage to CL&P’s and NSTAR Electric’s electric delivery systems. Approximately 71,000 and 320,000 of CL&P’s and NSTAR Electric's distribution customers, respectively, were without power as a result of damages caused by this blizzard.Order: In ~~addition to the blizzard, a major storm impacted CL&P’s service territory in the first quarter of 2013.~~

~~As of~~ March ~~31, 2013, the estimated storm restoration costs deferred for future recovery at CL&P, NSTAR Electric, PSNH, and WMECO were as follows:~~

(Millions of Dollars)

2012
and 2011

2013

Total

CL&P

$
465.3

$
32.4

$
497.7

NSTAR Electric

65.4

80.4

145.8

PSNH

33.3

2.6

35.9

WMECO

35.9

-

35.9

Total

$
599.9

$
115.4

$
715.3

The magnitude of these storm restoration costs met the criteria for cost deferral in Connecticut, New Hampshire, and Massachusetts and as a result, the storms had no material impact on the results of operations of CL&P, NSTAR Electric, PSNH and WMECO. We believe our response to all of these storms was prudent and therefore we believe it is probable that CL&P, NSTAR Electric, PSNH and WMECO will be allowed to recover the deferred storm restoration costs. Each operating company will seek recovery of its estimated deferred storm restoration costs through its applicable regulatory recovery process.

~~Connecticut March 2013 Storm Filing:~~ ~~On March 28,~~ 2013, CL&P filed a request with PURA for approval to recover ~~the~~storm restoration costs ofassociated with five major storms, all of which occurred in ~~2012~~2011 and ~~2011.~~2012. CL~~&P requested approval of approximately $462 million in prudently incurred~~&P’s deferred storm restoration ~~costs.~~costs associated with these major storms totaled $462 million. Of that amount, approximately $414 million is subject to recovery in rates after giving effect to CL&P’s agreement to forego the recovery of $40 million of previously deferred storm restoration costs ~~associated with Tropical Storm Irene and the October snowstorm under the merger-related PURA-approved Connecticut comprehensive settlement agreement (Connecticut settlement agreement),~~ as well as an existing storm reserve fund balance of approximately $8 million. ~~The~~During the second half of 2013, the PURA proceeded with the storm ~~reserve fund balance is an accumulation~~recovery review issuing discovery requests, holding hearings and ultimately on March 12, 2014, issuing a final decision on the level of ~~amounts previously collected from customers~~storm costs recovery.

In its final decision, the PURA approved recovery of $365 million of deferred storm restoration costs and ordered CL&P to capitalize approximately $18 million of the deferred storm restoration costs as utility plant, which will be recovered through depreciation expense in future rate proceedings. PURA will allow recovery of the $365 million with carrying charges in CL&P’s ~~existing distribution rate structure. CL&P is seeking to recover the $414 million, plus carrying costs, in its~~ distribution rates over a six-year period beginning on December 1, ~~2014,~~2014. The remaining costs were either disallowed or we believe will be recovered from other sources. These costs did not have a material impact on CL&P’s financial position, results of operations or cash flows.

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New Hampshire:

Generation: In 2013, the NHPUC opened a docket to investigate market conditions affecting PSNH’s ES rate, how PSNH will maintain just and reasonable rates in ~~accordance~~light of those conditions, and any impact of PSNH’s generation ownership on the New Hampshire competitive electric market. In a 2013 NHPUC staff report accepted by the NHPUC, the NHPUC staff recommended that the NHPUC examine whether default service rates remain sustainable on a going forward basis, define “just and reasonable” with respect to default service in the ~~Connecticut settlement agreement.~~

~~Massachusetts March~~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, ~~Storm Filing:~~ 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 ~~March~~November 1, 2013, ~~NSTAR Electric filed~~the Oversight Committee asked for a request with the DPU for approval to recover approximately $35 million of prudently incurred storm restoration costs, plus carrying costs, related to Tropical Storm Irene and the October snowstorm. NSTAR Electric is seeking to recover these costs in its distribution rates over a five-year period beginning on Januarypreliminary 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 ~~accordance with~~those generating assets.

On April 1, 2014, the ~~merger-related DPU-approved Massachusetts comprehensive settlement agreement.~~

~~NSTAR Electric intends~~NHPUC staff issued a “Preliminary Status Report Addressing the Economic Interest of PSNH’s Retail Customers as it Relates to ~~file~~the Potential Divestiture of PSNH’s Generating Plants”, which included a ~~proposal with~~consultant’s analysis of the ~~DPU in~~fair market value of PSNH generating assets and long-term power purchase contracts. The consultant’s analysis estimated the ~~latter half~~fair market value of ~~2013 for approval to recover the estimated deferred storm restoration costs, which was estimated~~PSNH’s generation assets to be ~~approximately $108~~$225 million as of ~~March~~December 31, 2013 ~~related~~and compared that amount to ~~Storm Sandy,~~a stated net book value of $660 million, implying potential “stranded costs” in excess of $400 million. NHPUC staff made three recommendations: (1) that any further actions relating to PSNH’s generating assets await a final decision in the ~~February 2013 blizzard,~~Clean Air Project (scrubber) prudence proceeding; (2) that existing laws regarding divestiture, energy service, and ~~other 2012 storms.~~

~~New Hampshire:~~ ~~On April 30, 2013,~~cost recovery be harmonized; and (3) that ISO-NE provide input on the economic and reliability consequences of retirement of PSNH’s fossil generating plants. In the event of generation asset divestiture or retirement, both present law and the PSNH ~~filed a request with~~Restructuring Settlement Agreement approved in 2000 require that the NHPUC provide stranded cost recovery to ~~increase distribution rates by $12.6 million,effective July 1, 2013. The increase primarily consists~~PSNH. We continue to believe all costs and generation investments are probable of $7.7 million associated with net plant additions and a $5 million increase to the current level of funding for the Major Storm Cost reserve. The requested items are consistent with the NHPUC approved 2010 distribution rate case decision. We expect the NHPUC to issue an order on PSNH’s request in June 2013. recovery.

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 ~~NU’s 2012~~the NU 2013 Form 10-K. There have been no material changes with regard to these critical accounting policies.

Other Matters

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

Contractual Obligations and Commercial Commitments: There have been ~~no material contractual obligations identified and~~ no material changes with regard to the contractual obligations and commercial commitments ~~previously~~ disclosed in the NU ~~2012~~2013 Form 10-K.

Web Site: Additional financial information is available through our web site atwww.nu.com.

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RESULTS OF OPERATIONS –— NORTHEAST UTILITIES AND SUBSIDIARIES

The following ~~table~~ provides the amounts and variances in operating revenues and expense line items for the condensed consolidated statements of income for NU included in this Quarterly Report on Form 10-Q for the three months ended March 31, ~~2013~~2014 and ~~2012. The three months ended March 31, 2013 amounts include the operations of NSTAR:~~ 2013:

											Operating Revenues and Expenses
			Operating Revenues and Expenses								For the Three Months Ended March 31,
			For the Three Months Ended March 31,												Increase/
(Millions of Dollars)	(Millions of Dollars)		2013		2012		Increase		Percent		2014		2013		(Decrease)			Percent
(Millions of Dollars)	(Millions of Dollars)		2013		2012		Increase		Percent
Operating Revenues	Operating Revenues		$	1,995.0	$	1,099.6	$	895.4	81.4	%	$	2,290.6	$	1,995.0	$	295.6		14.8	%
Operating Expenses:	Operating Expenses:
	Purchased Power, Fuel and Transmission			747.8		395.3		352.5	89.2
	Operations and Maintenance			346.1		262.0		84.1	32.1
	Depreciation			155.0		80.8		74.2	91.8
	Amortization of Regulatory Assets, Net			54.0		5.4		48.6	(a)
	Amortization of Rate Reduction Bonds			34.5		18.3		16.2	88.5
	Energy Efficiency Programs			105.8		37.3		68.5	(a)
	Taxes Other Than Income Taxes			132.9		86.1		46.8	54.4
		Total Operating Expenses		1,576.1		885.2		690.9	78.1
Purchased Power, Fuel and Transmission											978.2		747.8		230.4			30.8
Operations and Maintenance											351.7		346.1		5.6			1.6
Depreciation											150.8		155.0		(4.2		)	(2.7	)
Amortization of Regulatory Assets, Net											57.9		54.0		3.9			7.2
Amortization of Rate Reduction Bonds											—		34.5		(34.5		)	(100.0	)
Energy Efficiency Programs											138.8		105.8		33.0			31.2
Taxes Other Than Income Taxes											145.5		132.9		12.6			9.5
Total Operating Expenses											1,822.9		1,576.1		246.8			15.7
Operating Income	Operating Income		$	418.9	$	214.4	$	204.5	95.4	%	$	467.7	$	418.9	$	48.8		11.6	%

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

Operating Revenues

For the Three Months Ended March 31,

(Millions of Dollars)
2013

2012

Increase

Percent

Electric Distribution
$
1,374.2

$
786.0

$
588.2

74.8
%
Natural Gas Distribution

361.8

139.0

222.8

(a)

Total Distribution

1,736.0

925.0

811.0

87.7

Transmission

239.5

162.8

76.7

47.1

Total Regulated Companies

1,975.5

1,087.8

887.7

81.6

Other and Eliminations

19.5

11.8

7.7

65.3

Total Operating Revenues
$
1,995.0

$
1,099.6

$
895.4

81.4
%

(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 March 31,

2013

2012

Increase

Percent

Retail Electric Sales in GWh
13,796

8,271

5,525

66.8
%
Firm Natural Gas Sales in Million Cubic Feet
40,615

16,819

23,796

(a)

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

~~Our~~ Operating Revenues

	For the Three Months Ended March 31,
(Millions of Dollars)	2014		2013		Increase		Percent
Electric Distribution	$	1,585.9	$	1,374.2	$	211.7	15.4	%
Natural Gas Distribution	432.8		361.8		71.0		19.6
Total Distribution	2,018.7		1,736.0		282.7		16.3
Transmission	252.1		239.5		12.6		5.3
Total Regulated Companies	2,270.8		1,975.5		295.3		14.9
Other and Eliminations	19.8		19.5		0.3		1.5
Total Operating Revenues	$	2,290.6	$	1,995.0	$	295.6	14.8	%

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

	For the Three Months Ended March 31,
	2014	2013	Increase	Percent
Retail Electric Sales in GWh	14,348	13,796	552	4.0	%
Firm Natural Gas Sales in Million Cubic Feet	46,917	40,615	6,302	15.5

Operating revenues increased $295.6 million compared to the first quarter of 2013. The increase in revenue reflects higher retail electric and firm natural gas sales volumes as a result of the significantly colder than normal winter temperatures and the overall impact of higher wholesale energy costs in New England. The wholesale energy markets were impacted by higher natural gas transportation costs which, in addition to its impact on the cost of natural gas purchased on behalf of our retail natural gas customers, had an adverse impact on the cost of purchased electric energy for our retail electric customers. Fluctuations on wholesale energy costs are recovered from customers in rates and therefore have no impact on earnings.

As noted above, the increase in distribution revenues reflect an increase of approximately 4 percent in retail electric sales and 15.5 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 last year throughout New England. Weather-normalized retail electric sales (based on 30-year average temperatures) increased 1.3 percent in the first quarter of 2014, as compared to the same period in 2013, reflecting a steady improvement in economic conditions across our service territory. Weather-normalized total firm natural gas sales increased 3.6 percent in the first quarter of 2014, as compared to the same period in 2013, due primarily to residential and commercial customer growth.

The positive impacts on sales volume were partially offset by customer savings due to the impact of our respective utility-sponsored energy efficiency programs. 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 quarter of 2014, the recognition of lost base revenues increased $4.8 million compared to the first quarter of 2013.

The increase in transmission revenues, net of applicable eliminations, reflects the recovery of higher transmission expenses including ongoing investments in our transmission infrastructure.

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Purchased Power, Fuel and Transmission increased in the first quarter of ~~2013,~~2014, as compared to the first quarter of ~~2012,~~2013, due primarily to the ~~addition of NSTAR, which included electric distribution revenues of approximately $530 million, transmission revenues of approximately $60 million, natural gas revenues of approximately $200 million~~following:

(Millions of Dollars)	Increase/(Decrease)
Electric distribution segment fuel and energy supply costs	$	238.8
Firm natural gas sales related costs	33.9
Transmission segment costs	35.2
Other and eliminations	11.1
Partially offset by:
Electric distribution segment deferred fuel costs	(88.6		)
	$	230.4

Operations and other revenues of approximately $10 million, and the consolidation of CYAPC and YAEC revenues of approximately $15 million. Excluding the impact of NSTAR's operations and the consolidation of CYAPC and YAEC, our Operating Revenues Maintenance increased ~~due to the following:~~

Higher electric distribution segment revenues related to the portions that are included in regulatory commission approved tracking mechanisms that recover certain incurred costs and do not impact earnings. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods. The tracked electric distribution revenues increased due primarily to higher retail transmission revenues ($34.6 million), higher energy related revenues ($27.2 million) and higher federally mandated congestion charge delivery-related revenues ($8.6 million). Partially offsetting these increases were lower generation service revenues ($10.1 million), lower stranded cost recovery revenues ($9.1 million) and lower combined public benefits charge revenues ($4.2 million).

~~An increase in natural gas segment revenues due primarily to a 15.1 percent increase in Yankee Gas' sales volume related to colder weather~~ in the first quarter of ~~2013,~~2014, as compared to the first quarter of ~~2012.~~

~~The portion of electric distribution segment revenues that impacts earnings increased $15 million~~2013, due primarily to ~~a 4.7 percent~~the following:

(Millions of Dollars)	Increase/(Decrease)
Electric Distribution:
Bad debt expense	$	6.9
General and administrative	7.4
Pension and employee benefit costs	(15.3		)
Storm costs	(5.3		)
Total Electric Distribution	(6.3		)
Total Natural Gas Distribution	4.1
Total Distribution	(2.2		)
Total Transmission maintenance costs	2.4
Other and eliminations:
Integration and severance costs	6.9
Other	(1.5		)
Total Operations and Maintenance	$	5.6

The Operations and ~~2.8 percent~~Maintenance expense increase ~~in sales volume at CL&P~~of $5.6 million includes costs that are recovered through cost tracking mechanisms, which have no earnings impact. The Operations and ~~PSNH, respectively, related to colder weather~~Maintenance expenses that are recovered through base distribution rates (and therefore impact earnings) decreased $3.7 million in the first quarter of ~~2013,~~2014, as compared to the first quarter of ~~2012.~~2013, due primarily to a decrease in pension and employee benefit costs.

·
Improved transmission segment revenues resulting from a higher level of investment in transmission infrastructure and the recovery of higher overall expenses, which are tracked and result in a related increase in revenues. The increase in expenses is directly related to the increase in transmission plant, primarily at WMECO, including costs associated with higher property taxes, depreciation and operation and maintenance expenses.

~~Purchased Power, Fuel and Transmission~~Depreciation ~~increased~~decreased in the first quarter of ~~2013,~~2014, as compared to the first quarter of ~~2012,~~2013, due primarily to ~~the following:~~

~~(Millions of Dollars)~~
~~Increase/(Decrease)~~
~~The addition of NSTAR's operations~~
$
~~321.4~~
~~Higher fuel costs and higher transmission costs at PSNH~~
~~20.0~~
~~An increase related to higher sales at Yankee Gas~~
~~13.3~~
~~Higher transmission costs, deferred fuel costs and CfD costs, partially offset by~~
  ~~lower GSC supply costs~~
~~8.4~~
~~Other and eliminations~~
~~(10.6)~~
$
~~352.5~~

~~Operations and Maintenance~~~~increased~~a decrease in ~~the first quarter of 2013, as compared to the first quarter of 2012, due primarily to the following:~~

~~(Millions of Dollars)~~
~~Increase/(Decrease)~~
~~The addition of NSTAR’s operations~~
$
~~123.6~~
~~Partially offset by lower:~~
  ~~Electric distribution segment costs~~
~~(11.9)~~
  ~~General and administrative costs~~
~~(7.2)~~
  ~~Transmission segment costs~~
~~(5.1)~~
  ~~NU’s unregulated contracting business costs~~
~~(2.2)~~
  ~~PSNH’s generation business costs~~
~~(1.9)~~
  ~~Natural gas segment operating costs~~
~~(1.6)~~
  ~~Other and eliminations~~
~~(9.6)~~
$
~~84.1~~

~~Depreciation~~increased in the first quarter of 2013, as compared to the first quarter of 2012, due primarily to the addition of NSTAR's utility plant balances ($54.2 million) and an increase as a result of the consolidation of CYAPC and YAEC decommissioning collections ($~~13.7~~12.5 million)~~. Excluding the impact of NSTAR and the consolidation of CYAPC and YAEC, depreciation increased due primarily~~, partially offset by an increase related to higher utility plant balances resulting from completed construction projects placed into ~~service.~~service ($8.3 million).

Amortization of Regulatory Assets, Net increased in the first quarter of ~~2013,~~2014, as compared to the first quarter of ~~2012,~~2013, due primarily to the ~~addition of NSTAR’s amortization ($45.8 million).~~following:

(Millions of Dollars)

Increase/(Decrease)

Recovery of transition costs at NSTAR Electric

$
(31.2
)
Increases in the SCRC, ES and TCAM amortizations at PSNH

15.7

Amortization related to deferred energy efficiency program costs at CL&P

14.3

Other

5.1

$
3.9

Amortization of ~~RRBs~~Rate Reduction Bonds ~~increased~~ decreased in the first quarter of ~~2013,~~2014, as compared to the first quarter of ~~2012,~~2013, due ~~primarily~~ to the ~~addition~~maturity in 2013 of RRBs of NSTAR ~~Electric’s amortization ($15.1 million).~~Electric, PSNH, and WMECO.

Energy Efficiency Programs increased in the first quarter of ~~2013,~~2014, as compared to the first quarter of ~~2012,~~2013, due primarily to an increase in energy efficiency costs in accordance with the ~~addition of NSTAR's operations ($68.6 million).~~ three-year program guidelines established by the DPU at NSTAR Electric and WMECO and expanded energy conservation programs at CL&P in 2014. All costs are fully recovered through approved tracking mechanisms and therefore do not impact earnings.

Taxes Other Than Income Taxes increased in the first quarter of ~~2013,~~2014, as compared to the first quarter of ~~2012,~~2013, due primarily to ~~the addition of NSTAR's operations ($37.8 million). In addition, there was~~ an increase in property taxes ($7.5 million) as a result of both an increase in ~~Property, Plant~~utility plant balances and ~~Equipment related to our regulated capital programs~~property tax rates, and an increase in the ~~property~~Connecticut gross earnings tax ~~rates.~~($6 million) attributable to an increase in retail revenues.

Interest Expense

For the Three Months Ended March 31,

Increase/

(Millions of Dollars)
2013

2012

(Decrease)

Percent

Interest on Long-Term Debt
$
85.3

$
60.0

$
25.3

42.2
%
Interest on RRBs

0.6

1.4

(0.8)

(57.1)

Other Interest

(9.6)

5.0

(14.6)

(a)

$
76.3

$
66.4

$
9.9

14.9
%

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

Interest Expense increased $13.7 million in the first quarter of ~~2013,~~2014, as compared to the first quarter of ~~2012,~~2013, due primarily to the ~~addition~~absence of ~~NSTAR's operations ($22 million). Offsetting~~ the ~~impact of NSTAR’s operations, Other Interest decreased due primarily to a~~ favorable impact from the resolution of a state income tax audit in the first quarter of ~~2013.~~2013 ($8.8 million) and lower interest income on deferred transition costs ($4.5 million).

52

Other Income, Net

For the Three Months Ended March 31,

(Millions of Dollars)
2013

2012

Decrease

Percent

Other Income, Net
$
7.8

$
8.8

$
(1.0)

(11.4)
%

Other Income, Net decreased $6.1 million in the first quarter of ~~2013,~~2014, as compared to the first quarter of ~~2012,~~2013, due primarily to lower ~~AFUDC related to equity funds ($1.3 million) and lower net~~mark-to-market gains ~~on the NU supplemental benefit trust~~associated with marketable securities held in ~~2013 ($0.6 million), partially offset by the addition~~trust.
47

Table of ~~NSTAR ($0.9 million).~~Contents

Income Tax Expense

For the Three Months Ended March 31,

(Millions of Dollars)
2013

2012

Increase

Percent

Income Tax Expense
$
120.5

$
56.0

$
64.5

(a)
%

~~(a) Percent greater than 100 percent is not shown as it is not meaningful.~~Income Tax Expense

	For the Three Months Ended March 31,
(Millions of Dollars)	2014		2013		Increase		Percent
Income Tax Expense	$	141.5	$	120.5	$	21.0	17.4	%

Income Tax Expense increased in the first quarter of ~~2013,~~2014, as compared to the first quarter of ~~2012,~~2013, due primarily to ~~an increase in~~higher pre-tax earnings ($~~52.8 million NSTAR, $12.8 million CL&P and $4.6 million other affiliates)~~13.1 million), ~~partially offset by a~~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 higher state taxes ($3.7 million).

5348

Table of Contents

RESULTS OF OPERATIONS –— THE CONNECTICUT LIGHT AND POWER COMPANY ~~AND SUBSIDIARY~~

The following ~~table~~ provides the amounts and variances in operating revenues and expense line items for the ~~consolidated~~condensed statements of income for CL&P included in this Quarterly Report on Form 10-Q for the three months ended March 31, ~~2013~~2014 and ~~2012:~~ 2013:


			Operating Revenues and Expenses								Operating Revenues and Expenses
			For the Three Months Ended March 31,								For the Three Months Ended March 31,
(Millions of Dollars)	(Millions of Dollars)		2013		2012		Increase/		Percent		2014		2013		Increase		Percent
(Millions of Dollars)	(Millions of Dollars)		2013		2012		(Decrease)		Percent
Operating Revenues	Operating Revenues		$	624.1	$	592.0	$	32.1	5.4	%	$	734.6	$	624.1	$	110.5	17.7	%
Operating Expenses:	Operating Expenses:
	Purchased Power and Transmission			229.3		220.9		8.4	3.8
	Operations and Maintenance			108.9		132.9		(24.0)	(18.1)
	Depreciation			42.4		41.1		1.3	3.2
	Amortization of Regulatory Assets, Net			10.8		8.0		2.8	35.0
	Energy Efficiency Programs			22.8		21.9		0.9	4.1
	Taxes Other Than Income Taxes			60.2		55.3		4.9	8.9
		Total Operating Expenses		474.4		480.1		(5.7)	(1.2)
Purchased Power and Transmission											281.4		229.3		52.1		22.7
Operations and Maintenance											109.5		108.9		0.6		0.6
Depreciation											46.1		42.4		3.7		8.7
Amortization of Regulatory Assets, Net											29.9		10.8		19.1		(a)
Energy Efficiency Programs											42.7		22.8		19.9		87.3
Taxes Other Than Income Taxes											67.0		60.2		6.8		11.3
Total Operating Expenses											576.6		474.4		102.2		21.5
Operating Income	Operating Income		$	149.7	$	111.9	$	37.8	33.8	%	$	158.0	$	149.7	$	8.3	5.5	%

Operating Revenues

CL&P's retail sales were as follows:

For the Three Months Ended March 31,

2013

2012

Increase

Percent

Retail Sales in GWh
5,681

5,427

254

4.7
%

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

Operating Revenues

CL~~&P's~~&P’s retail sales were as follows:

	For the Three Months Ended March 31,
	2014	2013	Increase	Percent
Retail Sales in GWh	5,949	5,681	268	4.7	%

CL&P’s Operating ~~Revenues~~revenues increased $110.5 million compared to the first quarter of 2013. The increase in revenue reflects higher retail sales volumes as a result of the significantly colder than normal winter temperatures and the overall impact of higher wholesale energy costs in New England. The wholesale energy markets 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 on wholesale energy costs are recovered from customers in rates and therefore have no impact on earnings.

As noted above, the increase in base distribution revenues reflects an increase of 4.7 percent in retail sales. This increase was due primarily to the colder winter weather experienced in the first quarter of 2014, when the average daily temperature was 5 degrees lower than the same period in 2013.

The increase in transmission revenues reflects recovery of higher transmission expenses including ongoing investments in our transmission infrastructure.

Purchased Power and Transmission increased in the first quarter of ~~2013,~~2014, as compared to the first quarter of ~~2012, due primarily to:~~

A $26.7 million increase in distribution revenues related to the portions that are included in PURA approved tracking mechanisms that recover certain incurred costs and do not impact earnings. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods. The tracked distribution revenues increased due primarily to higher retail transmission revenues ($28.1 million), higher federally mandated congestion charge delivery-related revenues ($8.6 million) and higher other tracked revenues. Partially offsetting these increases were lower generation service revenues ($10.1 million) and lower combined public benefits charge revenues ($4.2 million).

~~A $10.2 million increase in the portion of distribution revenues that impacts earnings in the first quarter of~~ 2013, ~~as compared to the first quarter of 2012, due primarily toa 4.7 percent increase in sales volume due to colder weather in the first quarter of 2013, as compared to the first quarter of 2012.~~

A $4.8 million increase in transmission revenues resulting from an increased level of investment in transmission infrastructure and the recovery of higher overall expenses, which are subject to tracking mechanisms or processes and result in a related increase in revenues. The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation, and operation and maintenance expenses.

~~Purchased Power and Transmission~~ ~~increased in the first quarter of 2013, as compared to the first quarter of 2012,~~ due primarily to the following:

~~(Millions of Dollars)~~

~~Increase/(Decrease)~~

~~Transmission Costs~~

~~17.9~~

~~Deferred Fuel Costs~~

	Three Months Ended
(Millions of Dollars)	Increase/(Decrease)
GSC Supply Costs	$	101.1
Transmission Costs	6.5
Deferred Fuel Costs	(55.8		)
Other	0.3
	$	52.1

~~6.3~~

~~CfD Costs~~

~~5.2~~

~~GSC Supply Costs~~

~~(15.7)~~

~~Purchased Power Contracts~~

~~(5.2)~~

~~Other~~

~~(0.1)~~

~~8.4~~

The increase ~~in transmission costs was the result of an increase in the amortization of a retail transmission deferral. The decrease~~ in GSC supply costs was due primarily to ~~lower~~higher average supply ~~prices. The~~prices and an increase in GSC ~~supply costs~~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 suppliers that have been awarded the right to supply SS and LRS load through a competitive solicitation process. ~~These~~The increase in transmission costs was the result of an increase in the retail transmission deferral, which reflects the actual costs of transmission service compared to estimated billed amounts. The decrease in deferred fuel costs was due primarily to higher average supply prices, as compared to prices projected when standard service rates were set. Purchased Power and Transmission costs are included in ~~PURA approved~~regulatory-approved tracking mechanisms and do not impact earnings.

Operations and Maintenance ~~decreased~~increased in the first quarter of ~~2013,~~2014, as compared to the first quarter of ~~2012,~~2013, due ~~primarily~~ to ~~lower~~higher bad debt expense ($5.5 million), higher distribution maintenance ($7.9 million). The mild weather in the first quarter of 2012 allowed CL&P to perform its annual inspections and maintenance ahead of schedule, while the colder than normal weather, as well as two majors storms, in the first quarter of 2013, precluded CL&P from performing these procedures ahead of schedule. Management expects these routine maintenance procedures to be performed in 2013. Other costs that impacted the reduction in Operations and Maintenance included lower distribution and

~~transmission business expenses as a result of lower~~ general and administrative ~~expenses~~costs ($~~7.9~~2.3 million), higher routine maintenance costs ($1.5 million), and ~~lower~~ other ~~routine~~ operating ~~costs.~~ costs ($1 million). Offsetting these increases was a decrease in pension and PBOP costs ($9.7 million).

~~Amortization of Regulatory Assets, Net~~Depreciation increased in the first quarter of ~~2013,~~2014, as compared to the first quarter of ~~2012,~~2013, due primarily to ~~lower CTA transition costs ($5.3 million) and~~ higher ~~CTA revenues ($3.2 million). Partially offsetting these impacts were lower retail SBC revenues ($5.2 million).~~utility plant balances resulting from completed construction projects placed into service.

~~Taxes Other Than Income Taxes~~Amortization of Regulatory Assets, Net increased in the first quarter of ~~2013,~~2014, as compared to the first quarter of ~~2012,~~2013, due primarily to an increase in amortization expense related to previously deferred congestion charges.

Table of Contents

Energy Efficiency Programs increased in the first quarter of 2014, as compared to the first quarter of 2013, due primarily to expanded energy conservation programs in 2014. All costs are fully recovered through PURA-approved tracking mechanisms and therefore do not impact earnings.

Taxes Other Than Income Taxes increased in the first quarter of 2014, as compared to the first quarter of 2013, due primarily to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates ($3.9 million). In addition, there was an increase in the Connecticut gross earnings tax ~~($2.6 million)~~ attributable to an increase in ~~gross earnings and an increase~~retail revenues ($3.6 million).

Interest Expense increased $4.5 million in ~~property taxes ($1.9 million) as a result of an increase in Property, Plant and Equipment related to CL&P’s capital program and an increase in the property tax rates.~~

Interest Expense

For the Three Months Ended March 31,

Increase/

(Millions of Dollars)
2013

2012

(Decrease)

Percent

Interest on Long-Term Debt
$
32.6

$
31.5

$
1.1

3.5
%
Other Interest

(2.9)

2.0

(4.9)

(a)

$
29.7

$
33.5

$
(3.8)

(11.3)
%

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

~~Other Interest decreased in the~~ first quarter of ~~2013,~~2014, as compared to the first quarter of ~~2012,~~2013, due primarily to athe absence in 2014 of the favorable impact from the resolution of a state income tax audit in the first quarter of 2013.

~~Other Income, Net~~

For the Three Months Ended March 31,

(Millions of Dollars)
2013

2012

Decrease

Percent

Other Income, Net
$
4.2

$
5.3

$
(1.1)

(20.8)
%

Other Income, Net decreased $3.1 million in the first quarter of ~~2013,~~2014, as compared to the first quarter of ~~2012,~~2013, due primarily to lower ~~AFUDC related to equity funds ($0.6 million) and lower net~~mark-to-market gains ~~on the NU Supplemental benefit trust ($0.4 million).~~associated with marketable securities held in trust.

Income Tax Expense

For the Three Months Ended March 31,

(Millions of Dollars)
2013

2012

Increase

Percent

Income Tax Expense
$
39.2

$
29.7

$
9.5

32.0
%

	For the Three Months Ended March 31,
(Millions of Dollars)	2014		2013		Increase		Percent
Income Tax Expense	$	45.5	$	39.2	$	6.3	16.1	%

Income Tax Expense increased in the first quarter of ~~2013,~~2014, as compared to the first quarter of ~~2012,~~2013, due primarily to ~~an increase~~the absence in ~~pre-tax earnings ($12.8 million), partially offset by a~~2014 of the favorable impact from the resolution of a state income tax audit in the first quarter of 2013 ($2.9 million), higher pre-tax earnings ($1.6 million), and higher state taxes ($0.9 million).

~~LIQUIDITY~~EARNINGS SUMMARY

	For the Three Months Ended March 31,
(Millions of Dollars)	2014		2013
Net Income	$	79.3	$	85.0

CL&P’s earnings decreased $5.7 million in the first quarter of 2014, as compared to the first quarter of 2013, due primarily to the absence in 2014 of the favorable impact from the resolution of a state income tax audit in the first quarter of 2013 and higher property tax expense and depreciation. Partially offsetting these unfavorable earnings impacts were higher retail electric sales due primarily to colder weather in the first quarter of 2014, as compared to the first quarter of 2013.

LIQUIDITY

CL&P had cash flows provided by operating activities of $95.5 million in the first quarter of 2014, compared with $26.4 million in the first quarter of ~~2013, compared with cash flows used in operating activities of $47.1 million in the first quarter of 2012.~~2013. The improved cash flows were due primarily to the absence of cash disbursements for major storm restoration costs in the first quarter of 2014, as compared to the first quarter of 2013, and income tax refunds of ~~approximately $132~~$11.7 million ~~in cash disbursements for storm costs associated with Tropical Storm Irene and the October snowstorm~~ in the first quarter of 2012, the absence of approximately $27 million in 2012 CL&P customer bill credits, the favorable cash flow impacts associated with transmission regulatory tracking mechanisms of $16.1 million, and income tax refunds of2014, as compared to $1.6 million in the first quarter of 2013, ~~compared with income tax payments of $9.2 million in the first quarter of 2012. Partially offsetting improved~~partially offset by an unfavorable cash ~~flows was the change in~~flow impact relating to traditional working capital amounts principally due to the ~~changes in~~ timing of accounts ~~payable, accounts receivable~~receivables.

Investments in Property, Plant and ~~accrued liabilities.~~

~~Cash capital expenditures included~~Equipment on the accompanying ~~consolidated~~ 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. ~~CL&P’s cash capital expenditures totaled $89.4 million in~~In the first quarter of ~~2013, compared with $108.8 million in the first quarter of 2012.~~2014, investments for CL&P were $108 million.

On ~~January 15, 2013,~~April 24, 2014, CL&P issued ~~$400~~$250 million of ~~2.5~~4.30 percent ~~first mortgage bonds that will~~2014 Series A First Mortgage Bonds, due to mature ~~on January 15, 2023.~~in April 2044. The proceeds, net of issuance costs, were used to repay short-term borrowings from NU parent.

NU parent and certain of its subsidiaries, including CL~~&P’s~~&P, are parties to a joint five-year $1.45 billion revolving credit facility ~~borrowings of $89 million and intercompany loans related~~due to ~~NU's~~expire on September 6, 2018. The revolving credit facility is to be used primarily to backstop the $1.45 billion commercial paper program ~~borrowings~~at NU parent. The commercial paper program allows NU parent to issue commercial paper as a form of ~~$305.8 million.~~short-term debt to its subsidiaries, including CL&P. As of March 31, 2014 and December 31, 2013, there were intercompany loans from NU parent of $351.6 million and $287.3 million, respectively, to CL&P.

Additional financing activities in the first quarter of ~~2013~~2014 included ~~$38~~$42.8 million in common stock dividends paid to NU ~~parent~~parent.

On January 31, 2014, Moody’s upgraded corporate credit and ~~an increase in intercompany short-term borrowings~~securities ratings of ~~$111.1 million, which was offset~~CL&P by one level. On April 7, 2014, Fitch affirmed the ~~$394.8 million pay down of commercial paper and revolver borrowings described above.~~

~~CL&P uses available capital resources to fund its construction expenditures, meet debt requirements, pay costs, including storm-related costs, pay dividends and fund other~~ corporate ~~obligations. The current growth in CL&P’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, CL&P operates in an environment where recovery of its electric construction expenditures takes place over an extended period of time. 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 CL&P’s current liabilities exceeding current assets by approximately $231 million as of March 31, 2013.

As of March 31, 2013, approximately $125 million of CL&P's current liabilities relates to long-term debt that will be paid in the next 12 months. CL&P, with its strong credit ratings, has several options available in the financial markets to repay or refinance this maturity with the issuance of new long-term debt. CL&P will reduce its short-term borrowings with cash received from operating cash flows or with the issuance of new long-term debt, as deemed appropriate given its capital requirements and maintenance of its credit rating and ~~profile. Management expects the future operating cash flows~~outlook of CL~~&P, along with the access to financial markets, will be sufficient to meet any future operating requirements and capital investment forecasted opportunities.~~&P.

Table of Contents

RESULTS OF OPERATIONS –— NSTAR ELECTRIC COMPANY AND ~~SUBSIDIARIES~~SUBSIDIARY

The following ~~table~~ provides the amounts and variances in operating revenues and expense line items for the condensed consolidated statements of income for NSTAR Electric included in this Quarterly Report on Form 10-Q for the three months ended March 31, ~~2013~~2014 and ~~2012:~~ 2013:

											Operating Revenues and Expenses For the Three Months Ended March 31,
			Operating Revenues and Expenses
			For the Three Months Ended March 31,
(Millions of Dollars)			2013		2012		Increase/		Percent
(Millions of Dollars)			2013		2012		(Decrease)		Percent		2014		2013		Increase/ (Decrease)			Percent
Operating Revenues	Operating Revenues		$	592.3	$	556.5	$	35.8	6.4	%	$	666.2	$	592.3	$	73.9		12.5	%
Operating Expenses:	Operating Expenses:
	Purchased Power and Transmission			214.1		219.0		(4.9)	(2.2)
	Operations and Maintenance			92.3		148.2		(55.9)	(37.7)
	Depreciation			45.4		42.5		2.9	6.8
	Amortization of Regulatory Assets, Net			47.0		23.9		23.1	96.7
	Amortization of Rate Reduction Bonds			15.1		22.6		(7.5)	(33.2)
	Energy Efficiency Programs			51.7		46.9		4.8	10.2
	Taxes Other Than Income Taxes			32.2		30.9		1.3	4.2
		Total Operating Expenses		497.8		534.0		(36.2)	(6.8)
Purchased Power and Transmission											319.1		214.1		105.0			49.0
Operations and Maintenance											85.9		92.3		(6.4		)	(6.9	)
Depreciation											46.6		45.4		1.2			2.6
Amortization of Regulatory Assets, Net											15.7		47.0		(31.3		)	(66.6	)
Amortization of Rate Reduction Bonds											—		15.1		(15.1		)	(100.0	)
Energy Efficiency Programs											48.3		51.7		(3.4		)	(6.6	)
Taxes Other Than Income Taxes											32.2		32.2		—			—
Total Operating Expenses											547.8		497.8		50.0			10.0
Operating Income	Operating Income		$	94.5	$	22.5	$	72.0	(a)	%	$	118.4	$	94.5	$	23.9		25.3	%

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

Operating Revenues

NSTAR Electric's retail sales were as follows:

For the Three Months Ended March 31,

2013

2012

Increase

Percent

Retail Sales in GWh

5,194

5,090

104

2.0
%

Operating Revenues

NSTAR ~~Electric's~~Electric’s retail sales were as follows:

	For the Three Months Ended March 31,
	2014	2013	Increase	Percent
Retail Sales in GWh	5,358	5,194	164	3.2	%

NSTAR Electric’s Operating ~~Revenues~~revenues increased $73.9 million compared to the first quarter of 2013. The increase in revenue reflects higher retail sales volumes as a result of the significantly colder than normal winter temperatures and the overall impact of higher wholesale energy costs in New England. The wholesale energy markets 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 on wholesale energy costs are recovered from customers in rates and therefore have no impact on earnings.

As noted above, the increase in base distribution revenues reflects a 3.2 percent increase in retail sales. The increase in sales volume was due primarily to colder winter weather in the first quarter of 2014. The average daily temperature in Boston was over 3 degrees lower than the first quarter of 2013.

The positive impacts on sales volume were partially offset by customer savings due to the impact of our energy efficiency programs. NSTAR Electric is permitted to bill customers for lost base revenues related to reductions in sales volume as a result of its energy efficiency. In the first quarter of 2014, the recognition of lost base revenues increased $4.8 million compared to the first quarter of 2013.

The increase in transmission revenues reflects recovery of higher transmission expenses including continuing transmission infrastructure investments.

Purchased Power and Transmission increased in the first quarter of ~~2013,~~2014, as compared to the first quarter of ~~2012, due primarily to:~~

A $25 million increase in distribution revenues related to the portions that are included in DPU approved tracking mechanisms that recover certain incurred costs and do not impact earnings. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods. This increase primarily related to higher retail transmission revenues ($14.2 million), higher transition revenues ($11.5 million), higher energy efficiency program revenues ($5.8 million), and higher PAM revenues ($1.7 million), partially offset by lower Basic Service revenues ($8.2 million).

~~A $4.3 million increase in the portion of distribution revenues that impacts earnings.~~

~~Purchased Power~~~~and Transmission~~ ~~decreased in the first quarter of~~ 2013, ~~as compared to the first quarter of 2012,~~ due primarily to the following:

~~(Millions of Dollars)~~

~~Increase/(Decrease)~~

~~Basic Service Costs~~

~~(17.9)~~

~~Transmission Costs~~

(Millions of Dollars)	Three Months Ended Increase/(Decrease)
Basic Service Costs	$	106.8
Transmission Costs	18.8
Purchased Power Contracts	12.2
Deferred Fuel Costs	(32.8		)
	$	105.0

~~7.8~~

~~Deferred Fuel Costs~~

~~4.8~~

~~Other~~

~~0.4~~

~~(4.9)~~

The ~~decrease~~increase in Basic Service costs was ~~due~~ primarily related to ~~lower~~higher average supply prices. The increase in transmission costs was due primarily to a higher ~~regional rate leading~~RNS expense. The increase in purchased power contracts was due primarily to higher ~~regional network service costs, as well as higher forward capacity market reliability~~congestion charges. The ~~increase~~decrease in deferred fuel costs was due primarily to ~~lower~~higher average supply prices, as compared to the prices projected when Basic Service rates were set. ~~These~~Purchased Power and Transmission costs are included in ~~DPU approved~~regulatory-approved tracking mechanisms and do not impact earnings.

Operations and Maintenance decreased in the first quarter of ~~2013,~~2014, as compared to the first quarter of ~~2012,~~2013, due primarily to ~~the absence of the cumulative adjustment recorded in 2012 to establish a reserve against the regulatory asset related to Basic Service~~lower employee benefit costs ($6 million) and lower storm-related costs ($2 million), partially offset by higher bad debt ~~costs~~expense ($270.6 million). In addition, first quarter 2012 adjustments were recognized for changes in accounting estimates related primarily to the allowance for doubtful accounts, workers’ compensation, employee medical benefits,, and ~~general liability claims~~other operating expenses ($~~18.7~~1 million). ~~Also contributing to the decrease in costs was a March 2012 substation fire in theBack Bay/Prudential area of Boston ($9.5 million).~~

~~Amortization of Regulatory Assets, Net~~Depreciation , increased in the first quarter of ~~2013,~~2014, as compared to the first quarter of ~~2012,~~2013, due primarily to higher ~~amortization related to transition costs.~~utility plant balances resulting from completed construction projects placed into service.

5751

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~~Energy Efficiency Programs~~ ~~increased~~

Amortization of Regulatory Assets, Net decreased in the first quarter of ~~2013,~~2014, as compared to the first quarter of ~~2012,~~2013, due primarily to a decrease in the recovery of previously deferred transition costs.

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

Energy Efficiency Programs decreased in the first quarter of 2014, as compared to the first quarter of 2013, due primarily to a decrease in the amortization of previously deferred costs ($8 million), partially offset by an increase in energy efficiency costs incurred in accordance with the three-year program guidelines established by the DPU ($4.6 million). All costs are fully recovered through DPU-approved tracking mechanisms and therefore do not impact earnings.

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

Interest Expense increased $5.1 million in the first quarter of 2014, as compared to the first quarter of 2013, due primarily to lower regulatory interest income primarily from deferred transition costs ($4.7 million), as well as higher average long-term debt outstanding.

Other Income/(Loss), Net decreased $0.8 million in the first quarter of 2014, as compared to the first quarter of 2013, due primarily to lower gains on the deferred compensation plans.

Income Tax Expense

	For the Three Months Ended March 31,
(Millions of Dollars)	2014		2013		Increase		Percent
Income Tax Expense	$	39.2	$	31.3	$	7.9	25.2	%

Income Tax Expense increased in the first quarter of 2014, as compared to the first quarter of 2013, due primarily to higher pre-tax earnings ($6.3 million) and higher state taxes ($1.6 million).

EARNINGS SUMMARY

	For the Three Months Ended March 31,
(Millions of Dollars)	2014		2013
Net Income	$	58.1	$	48.1

NSTAR Electric’s earnings increased $10 million in the first quarter of 2014, as compared to the first quarter of 2013, due primarily to higher transmission margin, higher distribution revenues related to higher retail electric sales due primarily to colder weather in the first quarter in 2014, as compared to the first quarter of 2013, higher lost base revenues, and lower non-tracked operations and maintenance costs. Partially offsetting these favorable earnings impacts was higher interest cost, primarily on deferred transition costs.

LIQUIDITY

NSTAR Electric had cash flows provided by operating activities of $191.4 million in the first quarter of 2014, compared with $89.4 million in the first quarter of 2013. The increase in operating cash flows was due primarily to the absence of cash disbursements for major storm restoration costs associated with the February 2013 blizzard, a decrease in income tax payments in the first quarter of 2014, as compared to the first quarter of 2013, the absence of costs recovered in rates related to the RRBs that were fully amortized in the first quarter of 2013, and the absence of pension contributions in the first quarter of 2014, as compared to the first quarter of 2013.

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

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

	Operating Revenues and Expenses
	For the Three Months Ended March 31,
						Increase/
(Millions of Dollars)	2014		2013			(Decrease)			Percent
Operating Revenues	$	299.8	$	273.8		$	26.0		9.5	%
Operating Expenses:
Purchased Power, Fuel and Transmission	115.3		101.0			14.3			14.2
Operations and Maintenance	62.2		59.7			2.5			4.2
Depreciation	24.2		22.6			1.6			7.1
Amortization of Regulatory Assets/(Liabilities), Net	12.6		(3.1		)	15.7			(a)
Amortization of Rate Reduction Bonds	—		14.8			(14.8		)	(100.0	)
Energy Efficiency Programs	3.8		3.7			0.1			2.7
Taxes Other Than Income Taxes	17.7		17.0			0.7			4.1
Total Operating Expenses	235.8		215.7			20.1			9.3
Operating Income	$	64.0	$	58.1		$	5.9		10.2	%

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

Operating Revenues

PSNH’s retail sales were as follows:

	For the Three Months Ended March 31,
	2014	2013	Increase	Percent
Retail Sales in GWh	2,076	1,992	84	4.2	%

PSNH’s Operating revenues increased $26 million compared to the first quarter of 2013. The increase in revenue reflects higher retail sales volumes as a result of the significantly colder than normal winter temperatures and the overall impact of higher wholesale energy costs in New England. The wholesale energy markets 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 on wholesale energy costs are recovered from customers in rates and therefore have no impact on earnings.

As noted above, the increase in base distribution revenues reflects an increase of 4.2 percent in retail sales. PSNH experienced strong sales in 2014 due to colder winter weather than what was experienced in 2013. The average daily temperature in New Hampshire was over 5 degrees lower than the first quarter of 2013. Also reflected in this revenue increase was an increase of $3.3 million related to NHPUC-approved distribution rate increases effective July 1, 2013 as a result of a 2010 distribution rate case settlement.

The increase in transmission revenues reflects recovery of higher transmission expenses including ongoing investments in our transmission infrastructure.

Purchased Power, Fuel and Transmission increased in the first quarter of 2014, as compared to the first quarter of 2013, due primarily to an increase in generation fuel costs, partially offset by lower purchased power costs due to customer migration, lower renewable energy requirements set by the NHPUC, and lower regional greenhouse gas initiative auction proceeds. Purchased Power, Fuel and Transmission costs are included in regulatory-approved tracking mechanisms and do not impact earnings.

Operations and Maintenance increased in the first quarter of 2014, as compared to the first quarter of 2013, due primarily to an increase in routine maintenance costs at the generation business ($1.2 million), an increase in routine transmission maintenance costs ($0.9 million) and higher bad debt expense ($0.6 million), partially offset by other operating costs ($0.2 million).

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

Amortization of Regulatory Assets/(Liabilities), Net increased in the first quarter of 2014, as compared to the first quarter of 2013, due primarily to increases in the SCRC, ES and TCAM amortizations ($7.3 million, $4.8 million, and $6.2 million, respectively).

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

Income Tax Expense

	For the Three Months Ended March 31,
(Millions of Dollars)	2014		2013		Increase		Percent
Income Tax Expense	$	19.7	$	18.0	$	1.7	9.4	%

Income Tax Expense increased in the first quarter of 2014, as compared to the first quarter of 2013, due primarily to higher pre-tax earnings ($1.9 million).

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EARNINGS SUMMARY

	For the Three Months Ended March 31,
(Millions of Dollars)	2014		2013		Increase
Net Income	$	32.6	$	29.0	$	3.6

PSNH’s earnings increased due primarily to higher generation earnings and distribution retail revenues. The first quarter 2014 distribution retail revenues were favorably impacted by the PSNH rate increases effective July 1, 2013 as a result of the 2010 distribution rate case settlement and a 4.2 percent increase in retail sales. PSNH experienced strong sales in the first quarter of 2014 due to colder winter weather than what was experienced in 2013. Partially offsetting these favorable earnings impacts were higher operations and maintenance, depreciation and property tax expense.

LIQUIDITY

PSNH had cash flows provided by operating activities of $129.3 million in the first quarter of 2014, compared with $107.2 million in the first quarter of 2013. The improved cash flows were due primarily to the absence of a $35.1 million NUSCO Pension and PBOP Plan contribution in the first quarter of 2014, as compared to the first quarter of 2013, the favorable impact of the 2010 rate case decision related to the additional increase to annualized rates that was effective July 1, 2013, and the favorable cash flow impacts relating to changes in traditional working capital amounts. These favorable cash flow impacts were partially offset by income tax payments of $16.1 million in the first quarter of 2014, compared with income tax refunds of $15.3 million in the first quarter of 2013, and the absence of costs recovered in rates related to the RRBs that were fully amortized in the second quarter of 2013.

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RESULTS OF OPERATIONS — WESTERN MASSACHUSETTS ELECTRIC COMPANY

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

	Operating Revenues and Expenses For the Three Months Ended March 31,
(Millions of Dollars)	2014		2013		Increase/ (Decrease)			Percent
Operating Revenues	$	137.4	$	125.0	$	12.4		9.9	%
Operating Expenses:
Purchased Power and Transmission	49.4		40.1		9.3			23.2
Operations and Maintenance	22.6		20.9		1.7			8.1
Depreciation	10.3		9.0		1.3			14.4
Amortization of Regulatory (Liabilities)/Assets, Net	0.4		0.1		0.3			(a)
Amortization of Rate Reduction Bonds	—		4.7		(4.7		)	(100.0	)
Energy Efficiency Programs	11.9		8.3		3.6			43.4
Taxes Other Than Income Taxes	8.1		6.3		1.8			28.6
Total Operating Expenses	102.7		89.4		13.3			14.9
Operating Income	$	34.7	$	35.6	$	(0.9	)	(2.5	)%

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

Operating Revenues

WMECO’s retail sales were as follows:

	For the Three Months Ended March 31,
	2014	2013	Increase	Percent
Retail Sales in GWh	965	929	36	3.8	%

WMECO’s Operating Revenues increased $12.4 million in the first quarter of 2014, as compared to the first quarter 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.

·Base distribution revenues are consistent with 2013. WMECO’s kWh sales have no impact on earnings, as its revenues are decoupled from sales volumes.

·A $0.8 million increase in transmission revenues reflecting recovery of higher transmission expenses including investments in our transmission infrastructure, primarily related to the NEEWS project.

·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.

Purchased Power and Transmission increased in the first quarter of 2014, as compared to the first quarter of 2013, due primarily to an increase in supplier contract prices and an increase in customers returning to default service from third party suppliers. Purchased Power and Transmission costs are included in regulatory-approved tracking mechanisms and do not impact earnings.

Operations and Maintenance increased in the first quarter of 2014, as compared to the first quarter of 2013, due primarily to an increase in customer related expenses ($0.8 million), an increase in routine maintenance costs ($0.6 million), and an increase in distribution vegetation management costs ($0.3 million).

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

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

~~Interest Expense~~

For the Three Months Ended March 31,

Increase/

(Millions of Dollars)
2013

2012

(Decrease)

Percent

Interest on Long-Term Debt
$
19.6

$
22.3

$
(2.7)

(12.1)
%
Interest on RRBs

0.4

1.3

(0.9)

(69.2)

Other Interest

(4.1)

(5.8)

1.7

29.3

$
15.9

$
17.8

$
(1.9)

(10.7)
%

~~Interest expense decreased~~Taxes Other Than Income Taxes increased in the first quarter of ~~2013,~~2014, as compared to the first quarter of ~~2012,~~2013, due primarily to ~~lower average long-term bond rates, partially offset by lower regulatory interest income primarily from deferred transition costs.~~ an increase in property taxes as a result of both an increase in utility plant balances and property tax rates.

~~Income Tax~~Interest Expense

For the Three Months Ended March 31,

(Millions of Dollars)
2013

2012

Increase

Percent

Income Tax Expense
$
31.3

$
2.0

$
29.3

(a)
%

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

~~Income Tax Expense increased~~ decreased $0.6 million in the first quarter of ~~2013,~~2014, as compared to the first quarter of ~~2012, due primarily to an increase in pre-tax earnings including state tax impacts ($28.8 million).~~

~~EARNINGS SUMMARY~~

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

2013

2012
Income Before Merger-Related Costs
$
48.1

$
4.5
Merger-Related Costs (after-tax)

-

0.6
Net Income
$
48.1

$
3.9

~~Excluding the merger-related costs, NSTAR Electric’s~~ 2013, ~~earnings were $43.6 million higher than 2012~~ due primarily to the ~~absence~~reversal of ~~2012 adjustments recorded to establish a reserve against the regulatory asset~~interest expense related to ~~Basic Service bad debt costs ($17 million), and for changes~~a previously recognized wholesale billing adjustment.

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Other Income, Net decreased $0.4 million in ~~accounting estimates related~~the first quarter of 2014, as compared to the first quarter of 2013, due primarily to lower mark-to-market gains associated with marketable securities held in trust.

EARNINGS SUMMARY

	For the Three Months Ended March 31,
(Millions of Dollars)	2014		2013
Net Income	$	18.1	$	18.6

WMECO’s earnings decreased $0.5 million in the ~~allowance for doubtful accounts, workers’ compensation, employee medical benefits, and general liability claims ($11.4 million). Also contributing~~first quarter of 2014, as compared to the ~~increase was a March 2012 substation fire in theBack Bay/Prudential area~~first quarter of Boston ($4.1 million) and a reserve recorded relating to lost base revenues based on 2012 developments during hearings in the merger proceeding ($3.7 million). In addition, there were higher transmission revenues in 2013, due primarily to lower mark-to-market gains associated with marketable securities held in trust, higher operations and maintenance and depreciation expense. Partially offsetting these unfavorable earnings impacts was an ~~increased level~~increase in earnings related to the reversal of ~~investment in transmission infrastructure, as well as higher distribution revenues not included in tracking mechanisms. These factors are partially offset by higher depreciation and property taxes.~~ a previously established wholesale billing adjustment.

~~CAPITAL EXPENDITURES~~LIQUIDITY

~~A summary of capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized portions of pension expense, is as follows:~~

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

2013

2012
Transmission
$
49.3

$
32.2
Distribution:

  Basic Business

15.6

38.5
  Aging Infrastructure

27.3

8.1
  Load Growth

1.9

15.8
Total Distribution

44.8

62.4
Total
$
94.1

$
94.6

~~LIQUIDITY~~

~~NSTAR Electric~~WMECO had cash flows provided by operating activities of ~~$45.9~~$46.3 million in the first quarter of ~~2013,~~2014, compared with ~~$53~~$71 million in the first quarter of ~~2012 (amounts are net of RRB payments, which are included in financing activities).~~2013. The decrease in operating cash flows was due primarily to ~~an increase in cash disbursements for storm costs~~income tax payments of $14.1 million in the first quarter of ~~2013 associated~~2014, compared with ~~the February 2013 blizzard, as compared to cash disbursements for storm costs in the first quarter of 2012 associated with Tropical Storm Irene and the October snowstorm, a $20 million increase in~~ income tax ~~payments in the first quarter~~refunds of ~~2013, as compared to the first quarter of 2012, and a $4.3 million increase in pension contributions in the first quarter of 2013, as compared to the first quarter of 2012.~~

~~RESULTS OF OPERATIONS – PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES~~

The following table provides the amounts and variances in operating revenues and expense line items for the consolidated statements of income for PSNH included in this Quarterly Report on Form 10-Q for the three months ended March 31, 2013 and 2012:

Operating Revenues and Expenses

For the Three Months Ended March 31,
(Millions of Dollars)
2013

2012

Increase/

Percent

(Decrease)
Operating Revenues
$
273.8

$
243.0

$
30.8

12.7
%
Operating Expenses:

Purchased Power, Fuel and Transmission

101.0

81.0

20.0

24.7

Operations and Maintenance

59.7

65.0

(5.3)

(8.2)

Depreciation

22.6

21.2

1.4

6.6

Amortization of Regulatory Liabilities, Net

(3.1)

(2.6)

(0.5)

(19.2)

Amortization of Rate Reduction Bonds

14.8

13.9

0.9

6.5

Energy Efficiency Programs

3.7

3.6

0.1

2.8

Taxes Other Than Income Taxes

17.0

15.5

1.5

9.7

Total Operating Expenses

215.7

197.6

18.1

9.2

Operating Income
$
58.1

$
45.4

$
12.7

28.0
%

Operating Revenues

PSNH's retail sales were as follows:

For the Three Months Ended March 31,

2013

2012

Increase

Percent

Retail Sales in GWh
1,992

1,937

55

2.8
%

~~PSNH's Operating Revenues increased in the first quarter of 2013, as compared to the first quarter of 2012, due primarily to:~~

A $25 million increase in distribution revenues related to the portions that are included in NHPUC approved tracking mechanisms that recover certain incurred costs and do not impact earnings. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods. This increase is related primarily to higher energy related revenues ($27.2 million), higher retail transmission revenues ($4.1 million) and higher purchased power and fuel costs related revenues ($2.6 million). These higher revenues were partially offset by lower stranded cost recovery revenues ($9.1 million).

A $5.3 million increase in the portion of distribution revenues that impacts earnings resulting from the favorable impact of the 2010 rate case decision related to the additional increase to annualized rates that was effective July 1, 2012 and a 2.8 percent increase in sales volume due to colder than normal weather in the first quarter of 2013, as compared to the first quarter of 2012.

A $2 million increase in transmission revenues resulting from an increased level of investment in transmission infrastructure and the recovery of higher overall expenses, which are tracked and result in a related increase in revenues. The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation, and operation and maintenance expenses.

~~Purchased Power, Fuel and Transmission~~ increased in the first quarter of 2013, as compared to the first quarter of 2012, due primarily to an increase in fuel costs resulting from an increase in sales and an increase in transmission costs resulting from an increase in regional transmission rates leading to higher RNS costs.

~~Operations and Maintenance~~ decreased in the first quarter of 2013, as compared to the first quarter of 2012, due primarily to lower general and administrative costs ($1.6 million) and lower maintenance costs at the generation business ($1.9 million). These lower costs were partially offset by higher routine distribution maintenance costs ($0.4 million).

~~Other Income, Net~~

For the Three Months Ended March 31,

(Millions of Dollars)
2013

2012

Decrease

Percent

Other Income, Net
$
1.0

$
2.0

$
(1.0)

(50.0)
%

~~Other Income, Net decreased in the first quarter of 2013, as compared to the first quarter of 2012, due primarily to lower AFUDC related to equity funds.~~

~~Income Tax Expense~~

For the Three Months Ended March 31,

(Millions of Dollars)
2013

2012

Increase

Percent

Income Tax Expense
$
18.0

$
13.4

$
4.6

34.3
%

~~Income Tax Expense increased in the first quarter of 2013, as compared to the first quarter of 2012, due primarily to an increase in pre-tax earnings ($4.3 million).~~

~~LIQUIDITY~~

~~PSNH had cash flows provided by operating activities of $92.9~~$26.6 million in the first quarter of 2013 ~~compared with operating cash flows~~and the absence of ~~$2.5 million~~costs recovered in rates related to the RRBs that were fully amortized in the first quarter of 2012 (amounts are net of RRB payments, which are included in financing activities). The improved cash flows were due primarily to a reduction in NUSCO Pension Plan contributions of $52.6 million in the firstsecond quarter of 2013, ~~as compared to the first quarter of 2012, income tax refunds of $15.3 million in the first quarter of 2013, compared with income tax payments of $5.2 million in the first quarter of 2012, and~~partially offset by the favorable ~~impact of the 2010 rate case decision related~~cash flow impacts relating to ~~the additional increase to annualized rates that was effective July 1, 2012. In addition,~~ changes in traditional working capital amounts principally due to the changes in timing of accounts payable and ~~accrued liabilities also contributed to the improved operating cash flows.~~accounts receivables.

Table of Contents

~~RESULTS OF OPERATIONS – WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY~~

The following table provides the amounts and variances in operating revenues and expense line items for the consolidated statements of income for WMECO included in this Quarterly Report on Form 10-Q for the three months ended March 31, 2013 and 2012:

Operating Revenues and Expenses

For the Three Months Ended March 31,
(Millions of Dollars)
2013

2012

Increase/

Percent

(Decrease)
Operating Revenues
$
125.0

$
114.0

$
11.0

9.6
%
Operating Expenses:

Purchased Power and Transmission

40.1

40.5

(0.4)

(1.0)

Operations and Maintenance

20.9

22.6

(1.7)

(7.5)

Depreciation

9.0

7.7

1.3

16.9

Amortization of Regulatory Assets/(Liabilities), Net

0.1

(0.3)

0.4

(a)

Amortization of Rate Reduction Bonds

4.7

4.4

0.3

6.8

Energy Efficiency Programs

8.3

5.5

2.8

50.9

Taxes Other Than Income Taxes

6.3

4.9

1.4

28.6

Total Operating Expenses

89.4

85.3

4.1

4.8

Operating Income
$
35.6

$
28.7

$
6.9

24.0
%

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

Operating Revenues

WMECO's retail sales were as follows:

For the Three Months Ended March 31,

2013

2012

Increase

Percent

Retail Sales in GWh
929

911

18

2.1
%

~~WMECO's Operating Revenues increased in the first quarter of 2013, as compared to the first quarter of 2012, due primarily to:~~

A $7.9 million increase in transmission revenues resulting from an increased level of investment in transmission infrastructure, primarily related to the NEEWS projects, and the recovery of higher overall expenses, which are tracked and result in a related increase in revenues. The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation, and operation and maintenance expenses.

A $5.3 million increase in distribution revenues related to the portions that are included in DPU approved tracking mechanisms that recover certain incurred costs and do not impact earnings. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods. Included in these amounts are Basic Service, pension, transition and energy efficiency program costs.

~~Operations and Maintenance~~ decreased in the first quarter of 2013, as compared to the first quarter of 2012, due to lower distribution general and administrative expenses ($1 million) and lower uncollectible expenses ($1 million). Partially offsetting these decreases was an increase related to higher pension costs ($1.3 million), which are recovered through DPU approved tracking mechanisms and have no earnings impact.

~~Depreciation~~ increased in the first quarter of 2013, as compared to the first quarter of 2012, due primarily to higher utility plant balances resulting from completed construction projects placed into service related to WMECO's capital programs.

~~Energy Efficiency Programs~~increased in the first quarter of 2013, as compared to the first quarter of 2012, due primarily to an increase in expenses attributable to an increase in spending in accordance with the three-year program guidelines established by the DPU. All costs are fully recovered through DPU tracking mechanisms and therefore do not impact earnings.

~~Taxes Other Than Income Taxes~~ increased in the first quarter of 2013, as compared to the first quarter of 2012, due primarily to an increase in property taxes as a result of an increase in Property, Plant and Equipment related to WMECO’s capital program and an increase in the property tax rates.

~~Income Tax Expense~~

For the Three Months Ended March 31,

(Millions of Dollars)
2013

2012

Increase

Percent

Income Tax Expense
$
11.7

$
9.2

$
2.5

27.2
%

~~Income Tax Expense increased in the first quarter of 2013, as compared to the first quarter of 2012, due primarily to an increase in pre-tax earnings ($2.4 million).~~

~~LIQUIDITY~~

WMECO had cash flows provided by operating activities of $66.3 million in the first quarter of 2013, compared with operating cash flows of $0.7 million in the first quarter of 2012 (amounts are net of RRB payments, which are included in financing activities). The improved cash flows were due primarily to income tax refunds of $26.6 million in the first quarter of 2013, compared with income tax refunds of $0.8 million in the first quarter of 2012, and the absence in the first quarter of 2013 of $14.4 million in cash disbursements for storm costs made in the first quarter of 2012. In addition, changes in traditional working capital amounts principally due to the changes in timing of accounts payable and accrued liabilities contributed to the improved operating cash flows.

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. ~~The remaining unregulated wholesale portfolio held by Select~~NU’s Energy ~~includes contracts that are market risk-sensitive, including a wholesale energy sales contract through December 2013 with an agency~~Supply Risk Committee, comprised of ~~municipalities. As Select Energy's contract volumes are winding down,~~senior officers, reviews and ~~as the wholesale~~approves all large scale energy ~~sales contract is substantially hedged against price risks, we have limited exposure to commodity price risks. We have not~~related transactions entered into ~~any energy contracts for trading purposes.~~ 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 ~~independent power producers,~~IPPs, industrial companies, gas and electric utilities, oil and gas producers, financial institutions, and other energy marketers. Margin accounts exist within this diverse group, and we realize interest receipts and payments related to balances outstanding in these margin accounts. This wide customer and supplier mix generates a need for a variety of contractual structures, products and terms that, in turn, require us to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by our risk management process.

If the respective unsecured debt ratings of NU ~~parent~~or its subsidiaries were reduced to below investment grade by either Moody’s or S&P, certain of NU’s contracts would require additional collateral in the form of cash to be provided to counterparties and independent system operators. ~~If such an event occurred as of March 31, 2013, NU would have been required to provide additional collateral.~~ 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~~“Derivative Instruments,"” to the ~~consolidated~~ financial statements.

We have provided additional disclosures regarding interest rate risk management and credit risk management in Part II, Item 7A, ~~"Quantitative~~“Quantitative and Qualitative Disclosures about Market Risk,"” in ~~NU's 2012~~NU’s 2013 Form 10-K, which is incorporated herein by reference. There have been no additional risks identified and no material changes with regard to the items previously disclosed in the NU ~~2012~~2013 Form 10-K.

ITEM 4.
CONTROLS AND PROCEDURES

Management, on behalf of NU, CL&P, NSTAR Electric, PSNH and WMECO, evaluated the design and operation of the disclosure controls and procedures as of March 31, ~~2013~~2014 to determine whether they are effective in ensuring that the disclosure of required information is made timely and in accordance with the Securities Exchange Act of 1934 and the rules and regulations of the SEC. This evaluation was made under ~~management's~~management’s supervision and with ~~management's~~management’s participation, including the principal executive officers and principal financial officer as of the end of the period covered by this Quarterly Report on Form 10-Q. There are inherent limitations of disclosure controls and procedures, including the possibility of human error and the circumventing or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. The principal executive officers and principal financial officer have concluded, based on their review, that the disclosure controls and procedures of NU, CL&P, NSTAR Electric, PSNH and WMECO are effective to ensure that information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934 (i) is recorded, processed, summarized, and reported within the time periods specified in SEC rules and regulations and (ii) is accumulated and communicated to management, including the principal executive officers and principal financial officer, as appropriate to allow timely decisions regarding required disclosures.

There have been no changes in internal controls over financial reporting for NU, CL&P, NSTAR Electric, PSNH and WMECO during the quarter ended March 31, ~~2013, other than changes resulting from the April 10, 2012 merger with NSTAR,~~2014 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

57

Table of Contents

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~~“Legal Proceedings,"” and elsewhere in our ~~2012~~2013 Form 10-K, which disclosures are incorporated herein by reference. There have been no additional material legal proceedings identified and no material changes with regard to the legal proceedings previously disclosed in our ~~2012~~2013 Form 10-K.

ITEM 1A.

RISK FACTORS

We are subject to a variety of significant risks in addition to the matters set forth under ~~"Forward-Looking~~“Forward-Looking Statements,"” in Item 2, ~~"Management's~~“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~~“Risk Factors,"” in our ~~2012~~2013 Form 10-K, which risk factors are incorporated herein by reference. These risk factors should be considered carefully in evaluating our risk profile. There have been no additional risk factors identified and no material changes with regard to the risk factors previously disclosed in our ~~2012~~2013 Form 10-K.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table discloses purchases of ~~shares of~~ our common ~~stock~~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 and its Employee Savings Plan.

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, 2013

9,895

$
39.22
-
-
February 1 – February 28, 2013

20,091

41.29
-
-
March 1 – March 31, 2013

425,736

42.69
-
-
Total

455,722

$
42.55
-
-

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, 2014	503,821	$	43.30	—	—
February 1 – February 28, 2014	37,241	43.42		—	—
March 1 – March 31, 2014	138,094	44.52		—	—
Total	679,156	$	43.55	—	—

Table of Contents

ITEM 6. EXHIBITS
~~EXHIBITS~~

Each exhibit 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.}
Exhibit No.
Description
Listing of Exhibits (NU)
* 10.1
Composite Amended and Restated Indenture, effective January 2, 2014, between Yankee Gas Services Company and The Bank of New York Mellon Trust Company, N.A., successor as Trustee to The Bank of New York, as successor to Fleet National Bank (formerly known as The Connecticut National Bank, as Trustee, dated July 1, 1989 (Composite including all amendments) (incorporated by reference to Exhibit B to the Eleventh Supplemental Indenture, filed as Exhibit 10.2 hereto)
10.2
Eleventh Supplemental Indenture of Mortgage and Deed of Trust, dated as of January 1, 2014, between Yankee Gas Services Company and The Bank of New York Mellon Trust Company, N.A., successor as Trustee to The Bank of New York, as successor to Fleet National Bank (formerly known as The Connecticut National Bank)
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 May 2, 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 May 2, 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 May 2, 2014
Listing of Exhibits (CL&P)
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 May 2, 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 May 2, 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 May 2, 2014
Listing of Exhibits (NSTAR Electric)
* 4.1
A Form of 4.40% Debenture Due March 1, 2044. (Incorporated by reference to Exhibit 4 of the NSTAR Electric Company Current Report on Form 8-K, filed March 13, 2014, File No. 001-02301)
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 May 2, 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 May 2, 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 May 2, 2014
_Description59

Table of Contents

Listing of Exhibits (PSNH)

12		Ratio of Earnings to Fixed Charges

31		Certification of Leon J. Olivier, Chief Executive Officer of PSNH, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 2, 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 May 2, 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 May 2, 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 May 2, 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 May 2, 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 May 2, 2014

~~Listing of Exhibits (NU)~~