September 2007 Form 10-Q

____________________________________________________________________________________

[september2007form10qedgar001.jpg]


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

FORM 10-Q


[X]

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

 

 

 

For the Quarterly Period Ended September 30, 2007     

 

OR     

[  ]

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

 

 

 

For the transition period from ____________ to ____________


Commission
File Number

Registrant; State of Incorporation;
Address; and Telephone Number

I.R.S. Employer
Identification No.

 

 

 

1-5324

NORTHEAST UTILITIES
(a Massachusetts voluntary association)
One Federal Street
Building 111-4
Springfield, Massachusetts 01105
Telephone:  (413) 785-5871

04-2147929

 

 

 

0-00404

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

06-0303850

 

 

 

1-6392

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

02-0181050

 

 

 

0-7624

WESTERN MASSACHUSETTS ELECTRIC COMPANY
(a Massachusetts corporation)
One Federal Street
Building 111-4
Springfield, Massachusetts 01105
Telephone:  (413) 785-5871

04-1961130

____________________________________________________________________________________



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


 

Yes

No

 

 

 

 

Ö

 


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


 

Large
Accelerated Filer

 

Accelerated
Filer

 

Non-accelerated
Filer

 

 

 

 

 

 

Northeast Utilities

Ö

 

 

 

 

The Connecticut Light and Power Company

 

 

 

 

Ö

Public Service Company of New Hampshire

 

 

 

 

Ö

Western Massachusetts Electric Company

 

 

 

 

Ö


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


 

Yes

No

 

 

 

Northeast Utilities

 

Ö

The Connecticut Light and Power Company

 

Ö

Public Service Company of New Hampshire

 

Ö

Western Massachusetts Electric Company

 

Ö


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

Company - Class of Stock

Outstanding at October 31, 2007

Northeast Utilities
Common stock, $5.00 par value


155,002,850 shares

 

 

The Connecticut Light and Power Company
Common stock, $10.00 par value


6,035,205 shares

 

 

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


301 shares

 

 

Western Massachusetts Electric Company
Common stock, $25.00 par value


434,653 shares


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


Public Service Company of New Hampshire and Western Massachusetts Electric Company meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and therefore filed their 2006 Form 10-K with the reduced disclosure format specified in General Instruction I(2) to Form 10-K.





GLOSSARY OF TERMS

The following is a glossary of frequently used abbreviations or acronyms that are found in this report.  

 

 

NU COMPANIES,  SEGMENTS OR INVESTMENTS:

 

 

CL&P

The Connecticut Light and Power Company

CRC

CL&P Receivables Corporation

HWP

Holyoke Water Power Company

Mt. Tom

Mt. Tom generating plant

NGC

Northeast Generation Company

NGS

Northeast Generation Services Company and Subsidiaries

NU or the company

Northeast Utilities

NU Enterprises

At September 30, 2007, NU Enterprises, Inc., is comprised of Select Energy, NGS, E.S. Boulos Company (Boulos), the Connecticut division of SECI (SECI-CT) and NU Enterprises parent.  For further information, see Note 10, "Segment Information," to the condensed consolidated financial statements.

Parent and affiliates

Parent and affiliates is comprised of NU parent, NU's service companies, HWP (since January 1, 2007) and other subsidiaries, including Rocky River Realty Company and the Quinnehtuk Company (both real estate subsidiaries), Mode 1 Communications, Inc. (telecommunications) and the non-energy-related subsidiaries of Yankee (Yankee Energy Services Company, Yankee Energy Financial Services Company, and NorConn Properties, Inc.).

PSNH

Public Service Company of New Hampshire

Regulated companies

NU's regulated companies, comprised of the electric distribution and transmission segments of CL&P, PSNH, WMECO, the generation segment of PSNH and Yankee Gas, which is a natural gas local distribution company.  For further information, see Note 10 "Segment Information," to the condensed consolidated financial statements.

SECI

Select Energy Contracting, Inc.

Select Energy

Select Energy, Inc.

SESI

Select Energy Services, Inc.

WMECO

Western Massachusetts Electric Company

Yankee

Yankee Energy System, Inc.

Yankee Gas

Yankee Gas Services Company

Woods Electrical

Woods Electrical Co., Inc. a portion of which was sold in April of 2006 and the remainder of which was wound down in the second quarter of 2007.  

 

 

REGULATORS:

 

 

 

DPU

Massachusetts Department of Public Utilities (formerly the Massachusetts Department of Telecommunications and Energy (DTE))

DPUC

Connecticut Department of Public Utility Control

FERC

Federal Energy Regulatory Commission

NHPUC

New Hampshire Public Utilities Commission

SEC

Securities and Exchange Commission




i



OTHER: 

 

 

 

AFUDC

Allowance For Funds Used During Construction

CFD

Contract for Differences

CTA

Competitive Transition Assessment

COLA

Cost of Living Adjustment

EPS

Earnings Per Share

ES

Default Energy Service

FASB

Financial Accounting Standards Board

FMCC

Federally Mandated Congestion Cost

GSC

Generation Service Charge

GWH

Gigawatt Hours

ISO-NE

New England Independent System Operator

KWH

Kilowatt-Hour

KV

Kilovolt

LOCs

Letters of Credit

MMCF

Million Cubic Feet

MW

Megawatt/Megawatts

NU 2006 Form 10-K

The Northeast Utilities and Subsidiaries combined 2006 Form 10-K as filed with the SEC

NYMEX

New York Mercantile Exchange 

OCC

Connecticut Office of Consumer Counsel

Regulatory ROE

The average cost of capital method for calculating the return on equity related to the distribution and generation segments excluding the wholesale transmission segment.

RMR

Reliability Must Run

ROE

Return on Equity

SBC

System Benefits Charge

SCRC

Stranded Cost Recovery Charge

SFAS

Statement of Financial Accounting Standards

TCAM

Transmission Cost Adjustment Mechanism

TSO

Transitional Standard Offer

UI

United Illuminating Corporation




ii


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

TABLE OF CONTENTS



 

Page

 

 

PART I - FINANCIAL INFORMATION

 

 

ITEM 1 - Condensed Consolidated Financial Statements for the Following Companies:

 

 

 

Northeast Utilities and Subsidiaries

 

 

Condensed Consolidated Balance Sheets (Unaudited) - September 30, 2007 and December 31, 2006

2

 

Condensed Consolidated Statements of Income (Unaudited) - Three and Nine Months Ended September 30, 2007 and 2006

4

 

Condensed Consolidated Statements of Cash Flows (Unaudited) - Nine Months Ended September 30, 2007 and 2006

5

 

Notes to Condensed Consolidated Financial Statements (Unaudited - all companies)

6

 

Report of Independent Registered Public Accounting Firm

36

 

The Connecticut Light and Power Company and Subsidiaries

 

 

Condensed Consolidated Balance Sheets (Unaudited) - September 30, 2007 and December 31, 2006

38

 

Condensed Consolidated Statements of Income (Unaudited) - Three and Nine Months Ended September 30, 2007 and 2006

40

 

Condensed Consolidated Statements of Cash Flows (Unaudited) - Nine Months Ended September 30, 2007 and 2006

41

 

Public Service Company of New Hampshire and Subsidiaries

 

 

Condensed Consolidated Balance Sheets (Unaudited) - September 30, 2007 and December 31, 2006

44

 

Condensed Consolidated Statements of Income (Unaudited) - Three and Nine Months Ended September 30, 2007 and 2006

46

 

Condensed Consolidated Statements of Cash Flows (Unaudited) - Nine Months Ended September 30, 2007 and 2006

47

 

Western Massachusetts Electric Company and Subsidiary

 

 

Condensed Consolidated Balance Sheets (Unaudited) - September 30, 2007 and December 31, 2006

50

 

Condensed Consolidated Statements of Income (Unaudited) - Three and Nine Months Ended September 30, 2007 and 2006

52

 

Condensed Consolidated Statements of Cash Flows (Unaudited) - Nine Months Ended September 30, 2007 and 2006

53

 




iii



 

Page

 

 

ITEM 2 - Management's Discussion and Analysis of Financial Condition and Results of Operations for the following  companies:

 

 

Northeast Utilities and Subsidiaries

54

 

The Connecticut Light and Power Company and Subsidiaries

76

 

Public Service Company of New Hampshire and Subsidiaries

80

 

Western Massachusetts Electric Company and Subsidiary

84

 

ITEM 3 - Quantitative and Qualitative Disclosures About Market Risk

87

 

 

ITEM 4 - Controls and Procedures

88

 

PART II - OTHER INFORMATION

 

ITEM 1 - Legal Proceedings

89

 

ITEM 1A - Risk Factors

89

 

ITEM 2 - Unregistered Sales of Equity Securities and Use of Proceeds

89

 

ITEM 6 - Exhibits

90

 

SIGNATURES

92

 





iv


NORTHEAST UTILITIES AND SUBSIDIARIES



1



NORTHEAST UTILITIES AND SUBSIDIARIES

 

 

 

 

 

 

 

 

 

 

 

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

 

 

 

(Unaudited)

 

 

 

 

 

 

 

September 30,

 

 

December 31,

 

 

2007

 

 

2006

 

 

(Thousands of Dollars)

ASSETS

 

 

 

 

 

 

 

 

 

 

 

Current Assets:

 

 

 

 

 

  Cash and cash equivalents

 

$                  207,653 

 

 

$                  481,911 

  Special deposits

 

31,919 

 

 

48,524 

  Investments in securitizable assets

 

339,309 

 

 

375,655 

  Receivables, less provision for uncollectible

 

 

 

 

 

    accounts of $18,924 in 2007 and $22,369 in 2006

 

326,900 

 

 

361,201 

  Unbilled revenues

 

70,515 

 

 

88,170 

  Fuel, materials and supplies

 

231,163 

 

 

173,882 

  Marketable securities - current

 

67,781 

 

 

67,546 

  Derivative assets - current

 

93,118 

 

 

88,857 

  Prepayments and other

 

47,273 

 

 

45,305 

 

 

1,415,631 

 

 

1,731,051 

 

 

 

 

 

 

Property, Plant and Equipment:

 

 

 

 

 

  Electric utility

 

7,312,198 

 

 

7,129,526 

  Gas utility

 

968,235 

 

 

858,961 

  Other

 

307,835 

 

 

299,389 

 

 

8,588,268 

 

 

8,287,876 

    Less: Accumulated depreciation: $2,466,190 for electric

 

 

 

 

 

               and gas utility and $176,395 for other in 2007;

 

 

 

 

 

               $2,440,544 for electric and gas utility and

 

 

 

 

 

               $174,562 for other in 2006

 

2,642,585 

 

 

2,615,106 

 

 

5,945,683 

 

 

5,672,770 

  Construction work in progress

 

931,358 

 

 

569,416 

 

 

6,877,041 

 

 

6,242,186 

 

 

 

 

 

 

Deferred Debits and Other Assets:

 

 

 

 

 

  Regulatory assets

 

2,101,115 

 

 

2,449,132 

  Goodwill

 

287,591 

 

 

287,591 

  Prepaid pension

 

108,988 

 

 

21,647 

  Marketable securities - long-term

 

56,733 

 

 

50,843 

  Derivative assets - long-term

 

264,723 

 

 

271,755 

  Other

 

227,162 

 

 

249,031 

 

 

3,046,312 

 

 

3,329,999 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Assets

 

$             11,338,984 

 

 

$             11,303,236 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 




2



NORTHEAST UTILITIES AND SUBSIDIARIES

 

 

 

 

 

 

 

 

 

 

 

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

 

 

 

(Unaudited)

 

 

 

 

 

 

 

September 30,

 

 

December 31,

 

 

2007

 

 

2006

 

 

(Thousands of Dollars)

LIABILITIES AND CAPITALIZATION

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities:

 

 

 

 

 

  Long-term debt - current portion

 

$                  154,286 

 

 

$                      4,877 

  Accounts payable

 

506,990 

 

 

569,940 

  Accrued taxes

 

21,150 

 

 

364,659 

  Accrued interest

 

73,709 

 

 

53,782 

  Derivative liabilities - current

 

90,921 

 

 

125,843 

  Other

 

201,400 

 

 

244,734 

 

 

1,048,456 

 

 

1,363,835 

 

 

 

 

 

 

Rate Reduction Bonds

 

1,015,232 

 

 

1,177,158 

 

 

 

 

 

 

Deferred Credits and Other Liabilities:

 

 

 

 

 

  Accumulated deferred income taxes

 

1,029,796 

 

 

1,099,433 

  Accumulated deferred investment tax credits

 

29,740 

 

 

32,427 

  Deferred contractual obligations

 

238,768 

 

 

271,528 

  Regulatory liabilities

 

857,048 

 

 

809,324 

  Derivative liabilities - long-term

 

104,619 

 

 

148,557 

  Accrued postretirement benefits

 

172,423 

 

 

203,320 

  Other

 

379,156 

 

 

322,840 

 

 

2,811,550 

 

 

2,887,429 

 

 

 

 

 

 

Capitalization:

 

 

 

 

 

  Long-Term Debt

 

3,473,523 

 

 

2,960,435 

 

 

 

 

 

 

  Preferred Stock of Subsidiary - Non-Redeemable

 

116,200 

 

 

116,200 

 

 

 

 

 

 

  Common Shareholders' Equity:

 

 

 

 

 

    Common shares, $5 par value - authorized

 

 

 

 

 

      225,000,000 shares; 175,920,879 shares issued

 

 

 

 

 

      and 154,983,295 shares outstanding in 2007 and

 

 

 

 

 

      175,420,239 shares issued and 154,233,141 shares

 

 

 

 

 

      outstanding in 2006

 

879,604 

 

 

877,101 

    Capital surplus, paid in

 

1,463,520 

 

 

1,449,586 

    Deferred contribution plan - employee stock

 

 

 

 

 

      ownership plan

 

(28,501)

 

 

(34,766)

    Retained earnings

 

914,622 

 

 

862,660 

    Accumulated other comprehensive income

 

6,305 

 

 

4,498 

    Treasury stock, 19,705,353 shares in 2007

 

 

 

 

 

      and 19,684,249 shares in 2006

 

(361,527)

 

 

(360,900)

  Common Shareholders' Equity

 

2,874,023 

 

 

2,798,179 

Total Capitalization

 

6,463,746 

 

 

5,874,814 

 

 

 

 

 

 

 

 

 

 

 

 

Total Liabilities and Capitalization

 

$             11,338,984 

 

 

$             11,303,236 

 

 

 

 

 

 

 

 

   

 

 

   

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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




3



NORTHEAST UTILITIES AND SUBSIDIARIES

 

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

2007

 

2006

 

2007

 

2006

 

 

(Thousands of Dollars, except share information)

 

 

 

Operating Revenues

 

$  1,451,080 

 

$   1,592,784 

 

$   4,547,426 

 

$  5,401,233 

 

 

 

Operating Expenses:

 

 

 

 

 

 

 

 

  Operation -

 

 

 

 

 

 

 

 

     Fuel, purchased and net interchange power

 

881,234 

 

1,046,184 

 

2,756,522 

 

3,699,885 

     Other

 

195,237 

 

248,956 

 

679,015 

 

827,278 

     Restructuring and impairment charges

 

 

1,287 

 

193 

 

9,712 

  Maintenance

 

53,858 

 

55,918 

 

159,703 

 

143,539 

  Depreciation

 

64,522 

 

61,355 

 

191,393 

 

179,840 

  Amortization

 

17,007 

 

(8,639)

 

19,795 

 

48,755 

  Amortization of rate reduction bonds

 

52,403 

 

49,161 

 

151,316 

 

141,836 

  Taxes other than income taxes

 

63,485 

 

62,179 

 

193,435 

 

193,046 

       Total operating expenses

 

1,327,746 

 

1,516,401 

 

4,151,372 

 

5,243,891 

Operating Income

 

123,334 

 

76,383 

 

396,054 

 

157,342 

 

 

 

 

 

 

 

 

 

Interest Expense:

 

 

 

 

 

 

 

 

  Interest on long-term debt

 

41,706 

 

37,448 

 

118,153 

 

105,269 

  Interest on rate reduction bonds

 

15,111 

 

18,197 

 

47,300 

 

57,060 

  Other interest

 

4,907 

 

4,479 

 

15,061 

 

18,105 

       Interest expense, net

 

61,724 

 

60,124 

 

180,514 

 

180,434 

Other Income, Net

 

10,734 

 

12,081 

 

36,676 

 

38,451 

Income from Continuing Operations Before

 

 

 

 

 

 

 

 

  Income Tax Expense/(Benefit)

 

72,344 

 

28,340 

 

252,216 

 

15,359 

Income Tax Expense/(Benefit)

 

20,778 

 

(75,702)

 

75,442 

 

(85,087)

Income from Continuing Operations Before

 

 

 

 

 

 

 

 

  Preferred Dividends of Subsidiary

 

51,566 

 

104,042 

 

176,774 

 

100,446 

Preferred Dividends of Subsidiary

 

1,390 

 

1,390 

 

4,169 

 

4,169 

Income from Continuing Operations

 

50,176 

 

102,652 

 

172,605 

 

96,277 

Discontinued Operations:

 

 

 

 

 

 

 

 

  Income from Discontinued Operations

 

 

15,945 

 

 

54,792 

  (Losses)/Gains from Sale/Disposition of Discontinued Operations

 

 (90)

 

 (1,605)

 

1,927 

 

 (8,083)

  Income Tax (Benefit)/Expense

 

 (38)

 

5,543 

 

761 

 

19,401 

(Loss)/Income from Discontinued Operations

 

 (52)

 

8,797 

 

1,166 

 

27,308 

Net Income

 

$        50,124 

 

$      111,449 

 

$      173,771 

 

$     123,585 

 

 

 

 

 

 

 

 

 

Basic and Fully Diluted Earnings Per Common Share:

 

 

 

 

 

 

 

 

  Income from Continuing Operations

 

$            0.32 

 

$            0.67 

 

$            1.12 

 

$           0.63 

  Income from Discontinued Operations

 

 

0.05 

 

 

0.17 

Basic and Fully Diluted Earnings Per Common Share

 

$            0.32 

 

$            0.72 

 

$            1.12 

 

$           0.80 

 

 

 

 

 

 

 

 

 

Basic Common Shares Outstanding (weighted average)

 

154,930,930 

 

153,883,480 

 

154,672,270 

 

153,651,610 

 

 

 

 

 

 

 

 

 

Fully Diluted Common Shares Outstanding (weighted average)

 

155,420,239 

 

154,320,675 

 

155,210,704 

 

154,036,770 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 




4



NORTHEAST UTILITIES AND SUBSIDIARIES

 

 

 

 

 

 

 

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

 

 

 

 

 

 

 

Nine Months Ended

 

September 30,

 

2007

 

2006

 

 (Thousands of Dollars)

 

 

Operating Activities:

   

 

 

  Net income

$               173,771 

 

$               123,585 

  Adjustments to reconcile to net cash flows

 

 

 

   provided by operating activities:

 

 

 

 Bad debt expense

19,983 

 

25,665 

 Depreciation

191,393 

 

182,752 

 Deferred income taxes

 (41,144)

 

130,432 

 Amortization

19,795 

 

48,755 

 Amortization of rate reduction bonds

151,316 

 

141,836 

 Amortization of recoverable energy costs

1,494 

 

6,481 

 Pension expense, net of capitalized portion

13,776 

 

20,626 

 Regulatory overrecoveries/(refunds)

95,766 

 

 (150,541)

 Derivative assets and liabilities

 (31,641)

 

 (78,422)

 Deferred contractual obligations

 (32,760)

 

 (72,255)

 Other non-cash adjustments

 (2,561)

 

940 

 Other sources of cash

 

9,375 

 Other uses of cash

 (33,101)

 

 (17,398)

   Changes in current assets and liabilities:

 

 

 

 Receivables and unbilled revenues, net

43,511 

 

658,768 

 Fuel, materials and supplies

 (57,281)

 

14,831 

 Investments in securitizable assets

18,137 

 

 (20,284)

 Other current assets

 (6,483)

 

23,533 

 Accounts payable

 (91,473)

 

 (461,183)

 Counterparty deposits and margin special deposits

20,858 

 

38,842 

 Taxes receivable and accrued taxes

 (350,529)

 

 (245,009)

 Other current liabilities

 (34,676)

 

 (1,063)

Net cash flows provided by operating activities

68,151 

 

380,266 

 

 

 

 

Investing Activities:

 

 

 

  Investments in property and plant

 (750,231)

 

 (600,302)

  Cash payments related to the sale of competitive businesses

 (1,908)

 

 (19,429)

  Proceeds from sales of investment securities

196,083 

 

127,010 

  Purchases of investment securities

 (199,964)

 

 (123,319)

  Rate reduction bond escrow

3,372 

 

 (54,357)

  Other investing activities

7,968 

 

3,874 

Net cash flows used in investing activities

 (744,680)

 

 (666,523)

 

 

 

 

Financing Activities:

 

 

 

  Issuance of common shares

8,988 

 

6,310 

  Issuance of long-term debt

655,000 

 

250,000 

  Retirement of rate reduction bonds

 (161,926)

 

 (117,947)

  Increase in short-term debt

           - 

 

246,000 

  Reacquisitions and retirements of long-term debt

 (4,877)

 

 (11,053)

  Cash dividends on common shares

 (89,745)

 

 (83,560)

  Other financing activities

 (5,169)

 

1,180 

Net cash flows provided by financing activities

402,271 

 

290,930 

Net (decrease)/increase in cash and cash equivalents

 (274,258)

 

4,673 

Cash and cash equivalents - beginning of period

481,911 

 

45,782 

Cash and cash equivalents - end of period

$               207,653 

 

$                 50,455 

 

 

 

 

 

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

 




5


NORTHEAST UTILITIES AND SUBSIDIARIES

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)



1.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (All Companies)


A.

Presentation


Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission (SEC).  The accompanying unaudited condensed consolidated financial statements should be read in conjunction with the entirety of this Form 10-Q, the first and second quarter 2007 reports on Form 10-Q and the Annual Reports of Northeast Utilities (NU or the company), The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH), and Western Massachusetts Electric Company (WMECO), which were filed with the SEC as part of the Northeast Utilities and subsidiaries combined 2006 Form 10-K (NU 2006 Form 10-K).  The accompanying condensed consolidated financial statements contain, in the opinion of management, all adjustments (including normal, recurring adjustments) necessary to present fairly NU's and the above companies' financial position at September 30, 2007, the results of operations for the three and nine months ended September 30, 2007 and 2006 and cash flows for the nine months ended September 30, 2007 and 2006.  The results of operations and statements of cash flows for the nine months ended September 30, 2007 and 2006 are not necessarily indicative of the results expected for a full year.  


The condensed consolidated financial statements of NU and its subsidiaries, as applicable, include the accounts of all their respective subsidiaries.  Intercompany transactions have been eliminated in consolidation.


The preparation of condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.


Certain reclassifications of prior period data included in the accompanying condensed consolidated financial statements have been made to conform with the current period presentation.  For the three and nine months ended September 30, 2006, wholesale contract market changes, net were separately stated on the condensed consolidated statements of income to increase the transparency of the mark-to-market related to Select Energy Inc.'s (Select Energy) wholesale marketing portfolio.  As the disclosure of this amount is currently not as meaningful as it was in prior periods, a benefit of $4.8 million and a loss of $14.9 million have been reclassified to fuel, purchased and net interchange power on the accompanying condensed consolidated statements of income for the three and nine months ended September 30, 2006, respectively.  For further information regarding Select Energy's derivatives, see Note 4, "Derivative Instruments," to the condensed consolidated financial statements.


In NU's, CL&P's, PSNH's and WMECO's condensed consolidated statements of income for the three and nine months ended September 30, 2006, the classification of certain cost and income items previously included in other income, net and interest expense was changed to operating expenses.  In addition, certain revenues were reclassified to operating expenses as a result of the change in classification of certain revenues and associated expenses from a gross presentation to a net presentation.  These changes for NU, CL&P, PSNH and WMECO for the three and nine months ended September 30, 2006 are as follows:


 

 

Three Months Ended September 30, 2006

 

Nine Months Ended September 30, 2006

(Millions of Dollars)

 

NU

 

CL&P

 

PSNH

 

WMECO

 

NU

 

CL&P

 

PSNH

 

WMECO

Decrease in operating revenues

 

$

(1.3)

 

$

 

$

(1.3)

 

$

 

$

(1.3)

 

$

 

$

(1.3)

 

$

Decrease/(increase) in
  operating expenses

 

$


0.4 

 

$


(1.0)

 

$


1.0 

 

$


 

$


(2.5)

 

$


(3.3)

 

$


0.2 

 

$


0.3 

Decrease in interest expense

 

$

2.7 

 

$

2.7 

 

$

 

$

 

$

7.4 

 

$

7.4 

 

$

 

$

(Decrease)/increase in other income

 

$

(1.8)

 

$

(1.7)

 

$

0.3 

 

$

 

$

(3.5)

 

$

(4.1)

 

$

1.1 

 

$

(0.3)


These reclassifications had no impact on the companies' results of operations, financial condition or cash flows.  



6


NU's condensed consolidated statements of income for the three and nine months ended September 30, 2006 classifies the past operations for the following as discontinued operations:  


·

Northeast Generation Company (NGC), including certain components of Northeast Generation Services Company (NGS),

·

The Mt. Tom generating plant (Mt. Tom) previously owned by Holyoke Water Power Company (HWP),

·

Select Energy Services, Inc. (SESI) and its wholly owned subsidiaries HEC/Tobyhanna Energy Project, Inc. and HEC/CJTS Energy Center LLC, and

·

A portion of the former Woods Electrical Co., Inc. (Woods Electrical).


For further information regarding these companies, see Note 3, "Assets Held for Sale and Discontinued Operations," to the condensed consolidated financial statements.


B.

Accounting Standards Issued But Not Yet Adopted


Fair Value Measurements:  On September 15, 2006, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 157, "Fair Value Measurements," which establishes a framework for identifying and measuring fair value and is required to be implemented in the first quarter of 2008.  SFAS No. 157 provides a fair value hierarchy, giving the highest priority to quoted prices in active markets, and is expected to be applied to fair value measurements of derivative contracts that are subject to mark-to-market accounting and to other assets and liabilities that are reported at fair value or subject to fair value measurements.  SFAS No. 157 is expected to be implemented prospectively with any adjustments to fair value reflected in earnings on January 1, 2008, similar to a change in estimate.  The company is evaluating the impact SFAS No. 157 will have on its financial statements.  


The Fair Value Option:  On February 15, 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities - including an amendment of FAS 115."  SFAS No. 159 is effective in the first quarter of 2008.  SFAS No. 159 allows entities to choose, at specified election dates, to measure at fair value eligible financial assets and liabilities that are not otherwise required to be measured at fair value.  If a company elects the fair value option for an eligible item, changes in that item's fair value in subsequent reporting periods must be recognized in earnings.  The company does not currently plan to elect the fair value option on existing financial instruments as of January 1, 2008.   


C.

Regulatory Accounting


The accounting policies of the regulated companies conform to accounting principles generally accepted in the United States of America applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation."


The transmission and distribution segments of CL&P, PSNH and WMECO, along with PSNH's generation segment and Yankee Gas Services Company's (Yankee Gas) gas distribution segment, continue to be cost-of-service rate regulated.  Management believes that the application of SFAS No. 71 to those segments continues to be appropriate.  Management also believes it is probable that the regulated companies will recover their investments in long-lived assets, including regulatory assets.  All material net regulatory assets are earning returns at either a market rate, or at a stipulated equity rate, except for securitized regulatory assets, which are not supported by equity.  Amortization and deferrals of regulatory assets are included on a net basis in amortization expense on the accompanying condensed consolidated statements of income.  


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


 

 

At September 30, 2007


(Millions of Dollars)

 

NU
Consolidated

 


CL&P

 


PSNH

 


WMECO

 

Yankee Gas
and Other

Securitized assets

 

$

962.3 

 

$

586.9 

 

$

286.6 

 

$

88.8 

 

$

Deferred benefit costs

 

 

287.6 

 

 

93.1 

 

 

71.8 

 

 

12.7 

 

 

110.0 

Income taxes, net

 

 

299.0 

 

 

271.1 

 

 

 

 

27.6 

 

 

0.3 

Unrecovered contractual obligations

 

 

198.9 

 

 

154.1 

 

 

 

 

44.8 

 

 

CTA and SBC undercollections

 

 

77.4 

 

 

77.4 

 

 

 

 

 

 

Regulatory assets offsetting regulated
  company derivative liabilities

 

 


47.0 

 

 


34.2 

 

 


12.8 

 

 


 

 


Other regulatory assets

 

 

228.9 

 

 

62.4 

 

 

77.6 

 

 

29.9 

 

 

59.0 

Totals

 

$

2,101.1 

 

$

1,279.2 

 

$

448.8 

 

$

203.8 

 

$

169.3 



7



 

 

At December 31, 2006


(Millions of Dollars)

 

NU
Consolidated

 


CL&P

 


PSNH

 


WMECO

 

Yankee Gas
and Other

Securitized assets

 

$

1,131.1 

 

$

707.2 

 

$

325.6 

 

$

98.3 

 

$

Deferred benefit costs

 

 

407.4 

 

 

155.8 

 

 

90.4 

 

 

25.8 

 

 

135.4 

Income taxes, net

 

 

308.0 

 

 

266.6 

 

 

5.5 

 

 

41.3 

 

 

(5.4)

Unrecovered contractual obligations

 

 

214.4 

 

 

163.7 

 

 

 

 

50.7 

 

 

CTA and SBC undercollections

 

 

100.5 

 

 

100.5 

 

 

 

 

 

 

Regulatory assets offsetting regulated
  company derivative liabilities

 

 


75.4 

 

 


36.0 

 

 


39.2 

 

 


 

 


0.2 

Other regulatory assets

 

 

212.3 

 

 

47.6 

 

 

63.8 

 

 

36.2 

 

 

64.7 

Totals

 

$

2,449.1 

 

$

1,477.4 

 

$

524.5 

 

$

252.3 

 

$

194.9 


Included in NU's other regulatory assets are the regulatory assets associated with the implementation of FASB Interpretation (FIN) 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143," totaling $51.9 million at September 30, 2007 and $46.4 million at December 31, 2006.  Of these amounts, $14 million and $13.7 million, respectively, have been approved for future recovery.  At this time, management believes that the remaining regulatory assets are also probable of recovery.  


The regulatory assets related to deferred benefit costs totaled $287.6 million at September 30, 2007, as compared to $407.4 million at December 31, 2006.  The $119.8 million decrease primarily relates to a pension plan remeasurement adjustment recorded in the second quarter of 2007 related to cost a of living adjustment (COLA) as well as changes in estimate recorded for both the Pension and PBOP Plans in the second and third quarters of 2007, respectively.  For additional information, see Note 9, "Pension Benefits and Postretirement Benefits Other Than Pensions," to the condensed consolidated financial statements.


The companies above had $13.2 million and $11.2 million of costs at September 30, 2007 and December 31, 2006, respectively, that are included in deferred debits and other assets - other on the accompanying condensed consolidated balance sheets.  These amounts represent costs that have not yet been approved by the applicable regulatory agency.  Management believes these assets are recoverable in future cost of service regulated rates.


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


 

 

At September 30, 2007


(Millions of Dollars)

 

NU
Consolidated

 


CL&P

 


PSNH

 


WMECO

 

Yankee Gas
and Other

Cost of removal

 

$

275.0 

 

$

124.1 

 

$

74.8 

 

$

24.2 

 

$

51.9 

Regulatory liabilities offsetting
  regulated company derivative assets

 

 


307.2 

 

 


306.1 

 

 


0.7 

 

 


 

 


0.4 

Generation service charge/FMCC
 overcollections

 

 


146.2 

 

 


146.2 

 

 


 

 


 

 


Other regulatory liabilities

 

 

128.6 

 

 

51.1 

 

 

35.1 

 

 

15.6 

 

 

26.8 

Totals

 

$

857.0 

 

$

627.5 

 

$

110.6 

 

$

39.8 

 

$

79.1 


 

 

At December 31, 2006


(Millions of Dollars)

 

NU
Consolidated

 


CL&P

 


PSNH

 


WMECO

 

Yankee Gas
and Other

Cost of removal

 

$

290.8 

 

$

134.4 

 

$

79.2 

 

$

23.6 

 

$

53.6 

Regulatory liabilities offsetting
  regulated company derivative assets

 

 


294.5 

 

 


294.5 

 

 


 

 


 

 


Generation service charge/FMCC
 overcollections

 

 


108.2 

 

 


108.2 

 

 


 

 


 

 


Other regulatory liabilities

 

 

115.8 

 

 

45.7 

 

 

36.5 

 

 

3.2 

 

 

30.4 

Totals

 

$

809.3 

 

$

582.8 

 

$

115.7 

 

$

26.8 

 

$

84.0 


For information regarding derivative assets, see Note 4, "Derivative Instruments," to the condensed consolidated financial statements.




8


D.

Allowance for Funds Used During Construction


The allowance for funds used during construction (AFUDC) is included in the cost of the regulated companies' utility plant and represents the cost of borrowed and equity funds used to finance construction.  The portion of AFUDC attributable to borrowed funds is recorded as a reduction of other interest expense, and the cost of equity funds is recorded as other income on the accompanying condensed consolidated statements of income, as follows:


 

For the Three Months Ended

 

For the Nine Months Ended

(Millions of Dollars, except percentages)

September  30, 2007

 

September 30, 2006

 

September 30, 2007

 

September 30, 2006

Borrowed funds

$

4.3    

 

$

3.3    

 

$

12.9    

 

$

9.4    

Equity funds

 

4.8    

 

 

4.2    

 

 

11.1    

 

 

10.5    

Totals

$

9.1    

 

$

7.5    

 

$

24.0    

 

$

19.9    

Average AFUDC rates

 

7.6% 

 

 

7.9% 

 

 

7.3% 

 

 

7.4% 


The regulated companies' average AFUDC rate is based on a Federal Energy Regulatory Commission (FERC) prescribed formula that develops an average rate using the cost of a company's short-term financings as well as a company's capitalization (preferred stock, long-term debt and common equity).  The average rate is applied to eligible construction work in progress (CWIP) amounts to calculate AFUDC.  Although AFUDC is recorded on 100 percent of CL&P's CWIP for its major transmission projects in southwest Connecticut, 50 percent of this AFUDC is being reserved as a regulatory liability to reflect current rate base recovery for 50 percent of the CWIP as a result of FERC transmission incentives.


E.

Income Taxes


Effective on January 1, 2007, NU implemented FIN 48, "Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109."  FIN 48 applies to all tax positions previously filed in a tax return and tax positions expected to be taken in a future tax return that have been reflected on the balance sheets.  FIN 48 addresses the methodology to be used prospectively in recognizing, measuring and classifying the amounts associated with tax positions that are deemed to be uncertain, including related interest and penalties.  Previously, NU recorded estimates for uncertain tax positions in accordance with SFAS No. 5, "Accounting for Contingencies."


As a result of implementing FIN 48, NU recognized a cumulative effect of a change in accounting principle of $32.5 million as a reduction to the January 1, 2007 balance of retained earnings.  The CL&P, PSNH and WMECO reductions/(benefits) to the January 1, 2007 balances of retained earnings were $15.6 million, $(1.6) million and $(0.4) million, respectively.  


Interest and Penalties:  Effective on January 1, 2007, NU’s accounting policy for the classification of interest and penalties related to FIN 48 is as follows:


·

Interest on uncertain tax positions is recorded and classified as a component of other interest expense.  NU recorded accrued interest expense of $17.4 million, which is included in the cumulative effect of a change in accounting principle as of January 1, 2007.  NU recorded accrued interest expense of $1.3 million and $5.1 million for the three and nine months ended September 30, 2007, respectively.  


·

No penalties have been recorded under FIN 48.  If penalties are recorded in the future, then the estimated penalties would be classified as a component of other income, net.  


Unrecognized Tax Benefits:  Upon adoption of FIN 48 on January 1, 2007, NU recorded a liability for unrecognized tax benefits totaling $73.5 million, of which $56.9 million would impact the effective tax rate, if recognized.  As of September 30, 2007, NU's liability for unrecognized tax liabilities totaled $91 million, of which $69.2 million would impact the effective tax rate, if recognized.


Tax Positions:  NU is currently undergoing tax audits, and it is reasonably possible as these audits progress that the liability for unrecognized tax benefits could change significantly in the next 12 months; however, management cannot estimate the amount of change at this time.




9


Tax Years:  The following table summarizes NU's tax years that remain subject to examination by major tax jurisdictions at January 1, 2007 and September 30, 2007:  


Description

 

Tax Years

Federal

 

2002 - 2006

Connecticut

 

1997 - 2006

New Hampshire

 

2003 - 2006

Massachusetts

 

2003 - 2006


F.

Sale of Customer Receivables


CL&P Receivables Corporation (CRC), a consolidated, wholly-owned subsidiary of CL&P, can sell up to $100 million of an undivided interest in its accounts receivable and unbilled revenues to a financial institution.  At September 30, 2007 and December 31, 2006, there were no such sales.  


At September 30, 2007 and December 31, 2006, amounts sold to CRC by CL&P but not sold to the financial institution totaling $339.3 million and $375.7 million, respectively, are included in investments in securitizable assets on the accompanying condensed consolidated balance sheets.  These amounts would be excluded from CL&P's assets in the event of CL&P's bankruptcy.  


On July 3, 2007, CL&P extended the bank commitment under the Receivables Purchase and Sale Agreement with CRC and the financial institution through June 30, 2008 and extended the facility termination date to June 21, 2012.  CL&P's continuing involvement with the receivables that are sold to CRC and the financial institution is limited to servicing those receivables.  


The transfer of receivables to the financial institution under this arrangement qualifies for sale treatment under SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities - A Replacement of SFAS No. 125."


G.

Cash and Cash Equivalents


Cash and cash equivalents include cash on hand and short-term cash investments that are highly liquid in nature and have original maturities of three months or less.  At the end of each reporting period, any overdraft amounts are reclassified from cash and cash equivalents to accounts payable.


H.

Special Deposits and Counterparty Deposits


To the extent Select Energy requires collateral from counterparties, or the counterparties require collateral from Select Energy, cash is paid to or by Select Energy as a part of the total collateral required based on Select Energy’s position in the transaction.  Select Energy's right to use cash collateral is determined by the terms of the related agreements.  Key factors affecting the unrestricted status of a portion of this cash collateral include the financial standing of Select Energy and of NU as its credit supporter.  


Special deposits paid to unaffiliated counterparties and brokerage firms totaled $27.9 million and $48.5 million at September 30, 2007 and December 31, 2006, respectively.  In addition, at September 30, 2007, PSNH also had $4 million on deposit with an unaffiliated counterparty related to an energy contract.  These amounts are recorded as current assets and are included as special deposits on the accompanying condensed consolidated balance sheets.  


Balances collected from counterparties resulting from Select Energy’s credit management activities totaled $0.4 million and $0.1 million at September 30, 2007 and December 31, 2006, respectively.  These amounts are recorded as current liabilities and are included as current liabilities - other on the accompanying condensed consolidated balance sheets.  


NU also had amounts on deposit related to four special purpose entities used to facilitate the issuance of rate reduction bonds and certificates.  These amounts totaled $99.2 million and $102.5 million at September 30, 2007 and December 31, 2006, respectively.  In addition, the company had $6.1 million and $11.2 million in other cash deposits held with unaffiliated parties at September 30, 2007 and December 31, 2006, respectively, primarily related to CL&P's transmission projects.  These amounts are included in deferred debits and other assets - other on the accompanying condensed consolidated balance sheets.




10


I.

Other Income, Net


The pre-tax components of other income/(loss) items are as follows:


NU

 

For the Three Months Ended

 

For the Nine Months Ended

(Millions of Dollars)

 

September 30, 2007

 

September 30, 2006

 

September 30, 2007

 

September 30, 2006

Other Income:  

 

 

 

 

 

 

 

 

 

 

 

 

  Investment income

 

$

4.2 

 

$

3.9 

 

$

18.6 

 

$

11.9 

  Gain on sale of investment in Globix

 

 

 

 

 

 

 

 

3.1 

  CL&P procurement fee

 

 

 

 

3.0 

 

 

 

 

8.5 

  AFUDC - equity funds

 

 

4.8 

 

 

4.2 

 

 

11.1 

 

 

10.5 

  Energy Independence Act incentives

 

 

0.1 

 

 

1.0 

 

 

5.0 

 

 

3.5 

  Conservation and load management incentives

 

 

1.4 

 

 

0.5 

 

 

1.8 

 

 

1.3 

  Other

 

 

0.2 

 

 

0.3 

 

 

0.8 

 

 

0.6 

Total Other Income

 

$

10.7 

 

$

12.9 

 

$

37.3 

 

$

39.4 

Other Loss:

 

 

 

 

 

 

 

 

 

 

 

 

  Investment write-downs

 

 

 

 

(0.7)

 

 

(0.5)

 

 

(0.7)

  Other

 

 

 

 

(0.1)

 

 

(0.1)

 

 

(0.2)

Total Other Loss

 

$

 

$

(0.8)

 

$

(0.6)

 

$

(0.9)

Total Other Income, Net

 

$

10.7 

 

$

12.1 

 

$

36.7 

 

$

38.5 


CL&P

 

For the Three Months Ended

 

For the Nine Months Ended

(Millions of Dollars)

 

September 30, 2007

 

September 30, 2006

 

September 30, 2007

 

September 30, 2006

Other Income:  

 

 

 

 

 

 

 

 

 

 

 

 

  Investment income

 

$

1.3 

 

$

1.4 

 

$

4.3 

 

$

4.4 

  CL&P procurement fee

 

 

 

 

3.0 

 

 

 

 

8.5 

  AFUDC - equity funds

 

 

4.7 

 

 

2.6 

 

 

9.0 

 

 

6.1 

  Energy Independence Act incentives

 

 

0.1 

 

 

1.0 

 

 

5.0 

 

 

3.5 

  Conservation and load management incentives

 

 

1.3 

 

 

0.3 

 

 

1.4 

 

 

0.5 

  Other

 

 

0.1 

 

 

0.2 

 

 

0.6 

 

 

0.6 

Total Other Income

 

$

7.5 

 

$

8.5 

 

$

20.3 

 

$

23.6 

Other Loss

 

$

 

$

 

$

 

$

(0.1)

Total Other Income, Net

 

$

7.5 

 

$

8.5 

 

$

20.3 

 

$

23.5 


PSNH

 

For the Three Months Ended

 

For the Nine Months Ended

(Millions of Dollars)

 

September 30, 2007

 

September 30, 2006

 

September 30, 2007

 

September 30, 2006

Other Income:  

 

 

 

 

 

 

 

 

 

 

 

 

  Investment income

 

$

0.2 

 

$

0.1 

 

$

0.6 

 

$

0.6 

  AFUDC - equity funds

 

 

 

 

1.1 

 

 

0.9 

 

 

3.4 

  Other

 

 

 

 

 

 

0.1 

 

 

Total Other Income

 

$

0.2 

 

$

1.2 

 

$

1.6 

 

$

4.0 


WMECO

 

For the Three Months Ended

 

For the Nine Months Ended

(Millions of Dollars)

 

September 30, 2007

 

September 30, 2006

 

September 30, 2007

 

September 30, 2006

Other Income:  

 

 

 

 

 

 

 

 

 

 

 

 

  Investment income

 

$

0.2 

 

$

0.3 

 

$

0.8 

 

$

0.4 

  Conservation and load management incentives

 

 

0.1 

 

 

0.2 

 

 

0.4 

 

 

0.8 

  AFUDC - equity funds

 

 

 

 

0.1 

 

 

 

 

0.1 

Total Other Income

 

$

0.3 

 

$

0.6 

 

$

1.2 

 

$

1.3 


Investment income for NU includes equity in earnings/(losses) of regional nuclear generating and transmission companies of $0.4 million and $0.8 million for the three months ended September 30, 2007 and 2006, respectively, and $1.5 million and $(0.4) million for the nine months ended September 30, 2007 and 2006, respectively.  Equity in earnings relates to the company's investment in the Connecticut Yankee Atomic Power Company (CYAPC), Maine Yankee Atomic Power Company, Yankee Atomic Electric Company and the Hydro-Quebec transmission system.


Based on developments in July of 2006, CYAPC management concluded that $10 million of CYAPC's regulatory assets were no longer probable of recovery and should be written off.  Because the contingency surrounding these regulatory assets existed at June 30, 2006, the write-off was recorded in the second quarter of 2006.  NU recorded a total after-tax write-off of $3 million ($2.1 million, $0.3 million and $0.6 million after-tax for CL&P, PSNH and WMECO, respectively) for its ownership share of this charge, which is included in investment income in the tables above.



11



J.

Other Taxes


Certain excise taxes levied by state or local governments are collected by NU from its customers.  These excise taxes are accounted for on a gross basis with collections in revenues and payments in expenses.  For the three and nine months ended September 30, 2007 and 2006, gross receipts taxes, franchise taxes and other excise taxes of $27 million and $84.9 million, respectively, for 2007 and $29.1 million and $86.9 million, respectively, for 2006, are included in operating revenues and taxes other than income taxes on the accompanying condensed consolidated statements of income.  Certain sales taxes are also collected by the regulated companies from their customers as agent for state and local governments and are recorded on a net basis with no impact on the accompanying condensed consolidated statements of income.  


2.

RESTRUCTURING AND IMPAIRMENT CHARGES (NU, NU Enterprises)


NU Enterprises recorded $0.2 million of pre-tax restructuring and impairment charges for the nine months ended September 30, 2007, relating to the decision to exit the competitive businesses.  The charges for the three and nine months ended September 30, 2006 were $10.4 million and $26 million, respectively.  The amounts related to continuing operations are included as restructuring and impairment charges on the condensed consolidated statements of income with the remainder included in discontinued operations.  These charges are included as part of the NU Enterprises reportable segment in Note 10, "Segment Information."  A summary of these pre-tax restructuring and impairment charges is as follows:  


 

 

For the Three Months Ended

 

For the Nine Months Ended

(Millions of Dollars)

 

September 30, 2007

 

September 30, 2006

 

September 30, 2007

 

September 30, 2006

Wholesale Marketing:

 

 

 

 

 

 

 

 

 

 

 

 

  Restructuring charges

 

$

 

$

0.1 

 

$

 

$

0.3 

Retail Marketing:

 

 

 

 

 

 

 

 

 

 

 

 

  Restructuring charges

 

 

 

 

0.6 

 

 

 

 

6.4 

Competitive Generation:

 

 

 

 

 

 

 

 

 

 

 

 

  Impairment charges

 

 

 

 

 

 

 

 

0.3 

  Restructuring charges

 

 

 

 

6.8 

 

 

 

 

9.5 

  Subtotal

 

$

 

$

6.8 

 

$

 

$

9.8 

Energy Services and Other:  

 

 

 

 

 

 

 

 

 

 

 

 

  Impairment charges

 

$

 

$

 

$

 

$

0.1 

  Restructuring charges

 

 

 

 

2.9 

 

 

0.2 

 

 

9.4 

  Subtotal

 

$

 

$

2.9 

 

$

0.2 

 

$

9.5 

Total restructuring and impairment charges

 

$

 

$

10.4 

 

$

0.2 

 

$

26.0 

Restructuring and impairment charges included in
 discontinued operations

 

$


 

$


9.1 

 

$


 

$


16.3 

Total restructuring and impairment charges included in
 continuing operations

 

$


 

$


1.3 

 

$


0.2 

 

$


9.7 


Restructuring charges totaling $0.2 million for nine months ended September 30, 2007, were recorded for energy services and other related to consulting fees, legal fees, employee-related and other costs incurred.  


For the three and nine months ended September 30, 2006, $0.1 million and $0.3 million, respectively, of restructuring charges were recorded for wholesale marketing for consulting, legal fees, employee-related and other costs.


On June 1, 2006, NU Enterprises completed the sale of Select Energy New York, Inc. (SENY).  In connection with this transaction, NU Enterprises recorded restructuring charges of $0.3 million for retail marketing, which is included in restructuring and impairment charges on the accompanying condensed consolidated statements of income for the nine months ended September 30, 2006.  In addition to the $0.3 million charge, restructuring charges of $0.6 million and $6.1 million were recorded for the three and nine months ended September 30, 2006, respectively, for consulting fees, legal fees, employee-related and other costs.


For the nine months ended September 30, 2006, $0.3 million of impairments were recorded for competitive generation related to certain long-lived assets of NGS that were no longer recoverable and were written off.  In addition, restructuring charges of $6.8 million and $9.5 million, respectively, were recorded for the three and nine months ended September 30, 2006, respectively, for consulting fees, legal fees, sale-related environmental fees, employee-related and other costs.


In the first quarter of 2006, $0.1 million of impairment charges were recorded in connection with the sale of a portion of Woods Electrical.  




12


On May 5, 2006, NU Enterprises completed the sale of SESI.  In connection with this transaction, NU Enterprises recorded a pre-tax restructuring charge of $6.5 million.  In the third quarter of 2006, an additional restructuring charge of $1.6 million was recorded related to additional charges incurred for the sale of SESI.  These charges are included in loss from sale of discontinued operations on the accompanying condensed consolidated financial statements of income.  In addition to these charges, restructuring charges of $0.3 million and $2 million were recorded for the three and nine months ended September 30, 2006, respectively, for consulting fees, legal fees, employee-related costs and other costs and a $1 million charge was recorded in the third quarter of 2006 related to NU’s guarantee of SESI’s performance under government contracts.  Offsetting the charges for the first nine months of 2006 is a restructuring benefit of $1.7 million from the gain on the sale of Massachusetts service location of Select Energy Contracting, Inc. - Connecticut (SECI-CT).


The following table summarizes the liabilities related to restructuring costs which are recorded in accounts payable and other current liabilities on the accompanying condensed consolidated balance sheets at September 30, 2007 and December 31, 2006:  




(Millions of Dollars)

 

Employee-
Related
Costs

 

Professional
and Other
Fees

 



Total

Restructuring liability as of January 1, 2005

 

$

 

$

 

$

Costs incurred

 

 

2.3 

 

 

7.4 

 

 

9.7 

Cash payments and other deductions/reversals

 

 

(0.5)

 

 

(3.2)

 

 

(3.7)

Restructuring liability as of December 31, 2005

 

 

1.8 

 

 

4.2 

 

 

6.0 

Costs incurred

 

 

3.3 

 

 

24.0 

 

 

27.3 

Cash payments and other deductions/reversals

 

 

(3.7)

 

 

(25.9)

 

 

(29.6)

Restructuring liability as of December 31, 2006

 

 

1.4 

 

 

2.3 

 

 

3.7 

Costs incurred

 

 

 

 

0.2 

 

 

0.2 

Cash payments and other deductions/reversals

 

 

(1.0)

 

 

(1.2)

 

 

(2.2)

Restructuring liability as of March 31, 2007

 

 

0.4 

 

 

1.3 

 

 

1.7 

Costs incurred

 

 

 

 

 

 

Cash payments and other deductions/reversals

 

 

(0.2)

 

 

 

 

(0.2)

Restructuring liability as of June 30, 2007

 

 

0.2 

 

 

1.3 

 

 

1.5 

Costs incurred

 

 

 

 

 

 

Cash payments and other deductions/reversals

 

 

(0.2)

 

 

(1.0)

 

 

(1.2)

Restructuring liability as of September 30, 2007

 

$

-  

 

$

0.3 

 

$

0.3 


3.

ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS (NU, NU Enterprises)


Assets Held for Sale:  In the first quarter of 2006, management determined that the retail marketing and competitive generation businesses met the held for sale criteria under applicable accounting guidance, and should be recorded at the lower of their carrying amount or fair value less cost to sell.  The retail marketing business was reduced to its fair value less cost to sell through an approximately $53 million pre-tax charge included in other operating expenses for the nine months ended September 30, 2006.  


At September 30, 2007, management continues to believe that the remaining wholesale marketing business, NGS, Boulos, and SECI-CT do not meet the held for sale criteria under applicable accounting guidance and therefore continue to be held and used and included in continuing operations.


Discontinued Operations:  NU's condensed consolidated statements of income present NGC, Mt. Tom, SESI, and a portion of Woods Electrical as discontinued operations for all periods presented.  These businesses were sold in 2006.  Under discontinued operations presentation, revenues and expenses of the businesses classified as discontinued operations are classified net of tax in income from discontinued operations on the condensed consolidated statements of income and all prior periods are reclassified.  Summarized financial information for the discontinued operations is as follows:  



13



 

 

For the Three Months Ended

 

For the Nine Months Ended

(Millions of Dollars)

 

September 30, 2007

 

September 30, 2006

 

September 30, 2007

 

September 30, 2006

Operating revenue

 

$

 

$

46.4 

 

$

 

$

157.6 

Income before income tax expense

 

 

 

 

15.9 

 

 

 

 

54.8 

(Losses)/gains on sale/disposition of
 discontinued operations

 

 


(0.1)

 

 


(1.6)

 

 


1.9 

 

 


(8.1)

Income tax (benefit)/expense

 

 

(0.1)

 

 

5.5 

 

 

0.7 

 

 

19.4 

Net income

 

 

 

 

8.8 

 

 

1.2 

 

 

27.3 


The gain on sale/disposition of discontinued operations of $1.9 million for the nine months ended September 30, 2007 primarily relates to the favorable resolution of contingencies from the completion of a cogeneration plant by SESI, partially offset by charges related to the sale of the competitive generation business, including a $1.9 million charge resulting from a purchase price adjustment from the sale of the competitive generation business recorded in the first quarter of 2007.


No intercompany revenues were included in discontinued operations for the three and nine months ended September 30, 2007.  Included in discontinued operations are $46.3 million and $144.6 million for the three and nine months ended September 30, 2006 of intercompany revenues that are not eliminated in consolidation due to the separate presentation of discontinued operations.  Of the 2006 amounts, $46.3 million and $144.4 million, respectively, represent revenues on intercompany contracts between the generation operations of NGC and Mt. Tom and Select Energy.  NGC's and Mt. Tom's revenues and earnings related to these contracts are included in discontinued operations while Select Energy's related and offsetting expenses and losses are included in continuing operations.  


Select Energy's obligation to NGC and Mt. Tom ended at the time of the sale of the competitive generation business.  See Note 6F, "Commitments and Contingencies - Guarantees and Indemnifications," for information related to a HWP coal purchase contract with a supplier and a related back-to-back agreement with the purchaser of the competitive generation business.  At September 30, 2007, NU does not have or expect to have significant ongoing involvement or continuing cash flows with the entities presented in discontinued operations.


The retail marketing business is not presented as discontinued operations because separate financial information is not available for this business.  


In the second quarter of 2007, the remaining contracts of Woods Electrical were completed.  The results of these contracts were not material to any of the periods presented, and discontinued operations presentation was not required.  


4.

DERIVATIVE INSTRUMENTS (NU, Select Energy, CL&P, PSNH, Yankee Gas)


Contracts that are derivatives and do not meet the requirements to be treated as a cash flow hedge or normal purchase or normal sale are recorded at fair value with changes in fair value included in earnings.  For those contracts that meet the definition of a derivative and meet the cash flow hedge requirements, including those related to initial and ongoing documentation, the changes in the fair value of the effective portion of those contracts are recognized in accumulated other comprehensive income.  Cash flow hedges impact net income when the forecasted transaction being hedged occurs, when hedge ineffectiveness is measured and recorded, when the forecasted transaction being hedged is no longer probable of occurring, or when there is accumulated other comprehensive loss and the hedge and the forecasted transaction being hedged are in a loss position on a combined basis.  The ineffective portion of contracts that meet the cash flow hedge requirements is recognized currently in earnings.  Derivative contracts designated as fair value hedges and the items they are hedging are both recorded at fair value with changes in fair value of both items recognized currently in earnings.  Derivative contracts that meet the requirements of a normal purchase or sale, and are so designated, are recognized in revenues or expenses, as applicable, when the quantity of the contract is delivered.  The change in fair value of a normal purchase or sale contract is not included in earnings.  


The tables below summarize current and long-term derivative assets and liabilities at September 30, 2007 and December 31, 2006.  The fair value of these contracts may not represent amounts that will be realized.  On the accompanying condensed consolidated balance sheets at September 30, 2007 and December 31, 2006, these amounts are recorded as current or long-term derivative assets or liabilities and are summarized as follows:



14



 

 

At September 30, 2007

 

 

Assets

 

Liabilities

 

 

 

 

Current

 

Long-Term

 

Current

 

Long-Term

 

Net Totals

(Millions of Dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NU Enterprises - Wholesale

 

$

45.1 

 

$

5.5 

 

$

(72.4)

 

$

(72.9)

 

$

(94.7)

Regulated Companies - Gas:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Non-trading

 

 

0.4 

 

 

 

 

 

 

 

 

0.4 

Regulated Companies - Electric:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Non-trading

 

 

47.6 

 

 

259.2 

 

 

(18.5)

 

 

(28.5)

 

 

259.8 

NU Parent:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Hedging

 

 

 

 

 

 

 

 

(3.2)

 

 

(3.2)

Totals

 

$

93.1 

 

$

264.7 

 

$

(90. 9)

 

$

(104.6)

 

$

162.3 


 

 

At December 31, 2006

 

 

Assets

 

Liabilities

 

 

 

 

Current

 

Long-Term

 

Current

 

Long-Term

 

Net Totals

(Millions of Dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NU Enterprises:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Wholesale

 

$

43.6 

 

$

22.3 

 

$

(82.3)

 

$

(110.1)

 

$

(126.5)

  Retail

 

 

0.2 

 

 

 

 

(0.1)

 

 

 

 

0.1 

Regulated Companies - Gas:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Non-trading

 

 

0.1 

 

 

 

 

(0.2)

 

 

 

 

(0.1)

Regulated Companies - Electric:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Non-trading

 

 

45.0 

 

 

249.5 

 

 

(43.2)

 

 

(32.0)

 

 

219.3 

NU Parent:  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Hedging

 

 

 

 

 

 

 

 

(6.5)

 

 

(6.5)

Totals

 

$

88.9 

 

$

271.8 

 

$

(125.8)

 

$

(148.6)

 

$

86.3 


For the regulated companies, offsetting regulatory assets or liabilities are recorded for the changes in fair value of their contracts, as these contracts are part of stranded costs or current regulated operating costs, and management believes that these costs will continue to be recovered or refunded in cost-of-service, regulated rates.  


NU Enterprises - Wholesale:  Certain electric derivative contracts are part of the remaining wholesale marketing business.  These contracts include wholesale short-term and long-term electricity supply and sales contracts, which include a contract to sell electricity to a utility under full requirements contracts (four other similar contracts expired on May 31, 2007), a contract to sell electricity to the New York Municipal Power Authority (NYMPA) (an agency that is comprised of municipalities) with a term of approximately six remaining years, and a contract to purchase the output of a generating plant which expired in May of 2007.  The fair value of the underlying electricity contracts was determined by prices from external sources for years through 2011 and generally by models based on natural gas prices and a heat-rate conversion factor to electricity for subsequent periods.  At September 30, 2007 and December 31, 2006, the net fair value of these wholesale contracts was a liability of $94.7 million and $126.5 million, respectively.  


For the three months ended September 30, 2007 and 2006, NU recorded a pre-tax charge of $2.5 million and a pre-tax benefit of $4.6 million, respectively, in fuel, purchased and net interchange power related to the wholesale contracts.  Similar amounts were recorded as charges of $4.6 million and $14.1 million for the nine months ended September 30, 2007 and 2006, respectively.  These amounts are associated with the mark-to-market on, and changes in, the fair value of certain long-dated wholesale electricity contracts in New England, New York and PJM and a contract to purchase generation products in New York.  A benefit of $0.2 million and a charge of $0.8 million was also recorded in fuel, purchased and net interchange power for the three and nine months ended September 30, 2006 related to the mark-to-market of certain asset specific sales and forward sales of electricity at hub points for generation contracts.


Regulated Companies - Gas - Non-Trading:  Yankee Gas' non-trading derivatives consist of peaking supply arrangements to serve winter load obligations and firm retail sales contracts with options to curtail delivery.  These contracts are subject to fair value accounting as these contracts are derivatives that cannot be designated as normal purchases and sales because of the optionality in the contract terms.  These non-trading derivatives at September 30, 2007 included current assets of $0.4 million.  At December 31, 2006, these non-trading derivatives included current assets of $50 thousand and current liabilities of $0.2 million.  An offsetting regulatory liability and an offsetting regulatory asset were recorded for these amounts as management believes that these costs will be refunded/recovered in rates.


Regulated Companies - Electric - Non-Trading:  CL&P has contracts with two independent power producers (IPP) to purchase power that contain pricing provisions that are not clearly and closely related to the price of power and therefore do not qualify for the normal purchases and sales exception.  The fair values of these IPP non-trading derivatives at September 30, 2007 include a derivative asset



15


with a fair value of $306.1 million and a derivative liability with a fair value of $30.6 million.  An offsetting regulatory liability and an offsetting regulatory asset were recorded, as these contracts are part of stranded costs, and management believes that these costs will continue to be recovered or refunded in cost-of-service, regulated rates.  At December 31, 2006, the fair values of these IPP non-trading derivatives included a derivative asset with a fair value of $289.6 million and a derivative liability with a fair value of $35.6 million.


CL&P has entered into Financial Transmission Rights contracts and bilateral basis swaps to limit the congestion costs associated with its standard offer contracts.  An offsetting regulatory asset or liability has been recorded as management believes that these costs will be recovered or refunded in rates.  At September 30, 2007, the fair value of these contracts is recorded as a derivative liability of $3.6 million on the accompanying condensed consolidated balance sheets.  At December 31, 2006, the fair value of those contracts was recorded as a derivative asset of $4.9 million and a derivative liability of $0.4 million on the accompanying condensed consolidated balance sheets.  


Pursuant to Public Act 05-01, "An Act Concerning Energy Independence," in August of 2007 the Department of Public Utility Control (DPUC) approved two CL&P contracts associated with the capacity of two generating projects to be built or modified.  The DPUC also approved two capacity-related contracts entered into by United Illuminating Corporation (UI), one with a generating project to be built and one with a new demand response project.  The total capacity of these four projects is expected to be 787 megawatts (MW).  The contracts, referred to as contracts for differences (CFDs), obligate the utilities to pay the difference between a set capacity price and the value that the projects receive in the New England Independent System Operator (ISO-NE) capacity markets for periods of up to 15 years beginning in 2009.  CL&P has an agreement with UI under which it will share the costs and benefits of these four CFDs, with 80 percent to CL&P and 20 percent to UI.  The ultimate cost to CL&P under the contracts will depend on the capacity prices that the projects receive in the ISO-NE capacity markets.  Due to the significance of the non-observable inputs associated with modeling the fair values of these derivative contracts, their fair values are not reflected in the accompanying condensed consolidated financial statements in accordance with Emerging Issues Task Force (EITF) No. 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities."  


PSNH has electricity procurement contracts that are non-trading derivatives at September 30, 2007.  The fair value of these contracts is calculated based on market prices and is recorded as a derivative asset of $0.6 million and a derivative liability of $12.8 million at September 30, 2007.  At December 31, 2006, the fair value was recorded as a derivative liability of $28.4 million.  An offsetting regulatory liability/asset was recorded as management believes that these costs will be refunded/recovered in rates as the energy is delivered.


In 2007, PSNH entered into a contract to assign transmission rights of a Hydro-Quebec direct current line in exchange for two energy call options.  These energy call options are derivatives that do not qualify for the normal purchases and sales exception and are accounted for at fair value calculated based on market prices.  At September 30, 2007, the options are recorded as a derivative asset of $0.1 million.  An offsetting regulatory liability was recorded, as the benefit of this arrangement will be refunded to customers in rates.


At December 31, 2006, PSNH had a contract to purchase oil that was a non-trading derivative, the fair value of which was recorded as a derivative liability of $10.8 million.  An offsetting regulatory asset was recorded as management believes that this cost will be recovered in rates through a deferral mechanism that tracks generation revenues and costs.  As of September 30, 2007, this contract has expired.


NU Parent - Hedging:   In March of 2003, to manage the interest rate characteristics of the company's long-term debt, NU parent entered into a fixed to floating interest rate swap on its $263 million, 7.25 percent fixed rate note that matures on April 1, 2012.  Under fair value hedge accounting, the changes in fair value of the swap and the hedged long-term debt instrument are recorded in interest expense.  The cumulative changes in the fair value of the swap and the long-term debt are recorded as derivative liabilities and decreases to long-term debt of $3.2 million at September 30, 2007 and $6.5 million at December 31, 2006.


5.

GOODWILL (Yankee Gas)


SFAS No. 142, "Goodwill and Other Intangible Assets," requires that goodwill and intangible assets deemed to have indefinite useful lives be reviewed for impairment at least annually by applying a fair value-based test.  NU uses October 1st as the annual goodwill impairment testing date.  Goodwill impairment is deemed to exist if the net book value of a reporting unit exceeds its estimated fair value and if the implied fair value of goodwill based on the estimated fair value of the reporting unit is less than the carrying amount.  


The only NU reporting unit that currently maintains goodwill is the Yankee Gas reporting unit, which is classified under the regulated companies - gas reportable segment.  The goodwill recorded related to the acquisition of Yankee Gas is not being recovered from the customers of Yankee Gas.  The goodwill balance was $287.6 million at both September 30, 2007 and December 31, 2006.  The company is currently in the process of completing the annual impairment test of the Yankee Gas goodwill as of October 1, 2007.  




16


For information regarding NU's reportable segments, see Note 10, "Segment Information," to the condensed consolidated financial statements.


6.

COMMITMENTS AND CONTINGENCIES


A.

Regulatory Developments and Rate Matters (CL&P, WMECO, Yankee Gas)


Connecticut:


CTA and SBC Reconciliation:  The Competitive Transition Assessment (CTA) allows CL&P to recover stranded costs, such as securitization costs associated with its rate reduction bonds, amortization of regulatory assets, and independent power producer over-market costs, while the System Benefits Charge (SBC) allows CL&P to recover certain regulatory and energy public policy costs, such as public education outreach costs, hardship protection costs, transition period property taxes, and displaced worker protection costs.


On March 30, 2007, CL&P filed its 2006 CTA and SBC reconciliation, which compared CTA and SBC revenues to revenue requirements, with the DPUC.  For the year ended December 31, 2006, total CTA cost of service exceeded CTA revenues by $5.6 million.  This amount was recorded as a regulatory asset on the accompanying condensed consolidated balance sheets.  In addition, CTA refunds for the period January 2006 through August 2006 totaled $99.8 million and resulted in an additional increase to CL&P’s CTA regulatory asset.  For the year ended December 31, 2006, the SBC cost of service exceeded SBC revenues by $24.3 million.


The DPUC issued a final decision in this docket on October 10, 2007.  That decision approved the CTA reconciliation with minor modifications.  The SBC reconciliation was approved with an adjustment to the timing of the recovery of a regulatory asset associated with a reserve for hardship customers accounts receivable greater than 90 days old totaling $17.2 million.  In its decision, the DPUC determined that CL&P should amortize and recover the $17.2 million regulatory asset over five years, or approximately $3.4 million per year.  The DPUC's decision also ordered CL&P to set the SBC rate to collect revenues at an annual level of $21 million, effective on January 1, 2008.  


Procurement Fee Rate Proceedings:  By law, CL&P was allowed to collect a fixed procurement fee of 0.50 mills per kilowatt-hour (KWH) from customers who purchased transitional standard offer (TSO) service from 2004 through the end of 2006.  On December 8, 2005, a draft decision was issued by the DPUC, which accepted the methodology proposed by CL&P to calculate the variable portion (incentive portion) of the procurement fee and authorized payment of $5.8 million for its 2004 incentive fee.  A final decision, which had been scheduled for December of 2005, was delayed by the DPUC, and the DPUC re-opened the docket to review additional testimony.


On April 17, 2007, CL&P filed an application with the DPUC for approval of incentive payments for the years 2005 and 2006.  The incentive portion of the procurement fee earned for 2005 was $6 million and for 2006 was $5.5 million.  The DPUC rejected this application and directed CL&P to refile after a DPUC decision on the 2004 case.  On October 19, 2007, the DPUC released a recommendation prepared by its consultant relative to statistical adjustments to the incentive calculations.  The DPUC has set a new schedule allowing for rebuttal of the consultant’s report.  The new schedule calls for a final decision in this docket in February of 2008.  


Management continues to believe that recovery of the $5.8 million asset related to CL&P's 2004 incentive payment, which was reflected in 2005 earnings, is probable.  No amounts have been recorded for the 2005 or 2006 incentive portions of CL&P's procurement fee.  The procurement fee expired at the end of 2006.


Purchased Gas Adjustment:  On September 9, 2005, the DPUC issued a draft decision regarding Yankee Gas Purchased Gas Adjustment (PGA) clause charges for the period of September 1, 2003 through August 31, 2004.  The draft decision disallowed approximately $9 million in previously recovered PGA revenues associated with two separate Yankee Gas unbilled sales and revenue adjustments.  At the request of Yankee Gas, the DPUC reopened the PGA hearings on September 20, 2005 and requested that Yankee Gas file supplemental information regarding the two adjustments.  Yankee Gas complied with this request.  The DPUC issued a new decision on April 20, 2006 requiring an audit of Yankee Gas' previously recovered PGA costs and deferred any conclusion on the $9 million of previously recovered revenues until the completion of the audit.  In a subsequent draft decision regarding Yankee Gas PGA charges for the period September 1, 2004 through August 31, 2005, an additional $2 million related to previously recovered revenues was also identified, bringing the total maximum amount at issue with regard to PGA clause charges under audit to approximately $11 million.  


The DPUC hired a consulting firm which has concluded an audit of Yankee Gas' previously recovered PGA costs and has submitted its final report.  A DPUC hearing was held on October 9, 2007.  Management believes the unbilled sales and revenue adjustments and resulting charges to customers through the PGA clause for both periods were appropriate.  Based on the facts of the case, the



17


supplemental information provided to the DPUC and the consultant’s final report, management believes the appropriateness of the PGA charges to customers for the time period under review will be approved, and has not reserved for any loss.


Massachusetts:


Transition Cost Reconciliations:  WMECO filed its 2005 transition cost reconciliation with the Massachusetts Department of Public Utilities (DPU) on March 31, 2006 and filed its 2006 transition cost reconciliation with the DPU on March 31, 2007.  The DPU opened a proceeding for these filings and evidentiary hearings were held on August 29, 2007.  The briefing process was completed during October of 2007.  The timing of the decision in this docket is uncertain.  Management does not expect the outcome of the DPU's review of these filings to have a material adverse impact on WMECO's net income, financial position or cash flows.


B.

NRG Energy, Inc. Exposures (CL&P, Yankee Gas)


Certain subsidiaries of NU, including CL&P and Yankee Gas, entered into transactions with NRG Energy, Inc. (NRG) and certain of its subsidiaries.  On May 14, 2003, NRG and certain subsidiaries of NRG filed voluntary bankruptcy petitions, and on December 5, 2003, NRG emerged from bankruptcy.  NU's NRG-related exposures as a result of these transactions relate to 1) the refunding of approximately $28 million of congestion charges previously withheld from NRG prior to the implementation of standard market design (SMD) on March 1, 2003, 2) the recovery of approximately $29.1 million of CL&P's station service billings from NRG, which is currently the subject of an arbitration, and 3) the recovery of, among other claimed damages, approximately $17.5 million of capital costs and expenses incurred by Yankee Gas related to an NRG subsidiary's generating plant construction project that has ceased.  


On July 20, 2007, the United States District Court for the District of Connecticut issued a ruling granting CL&P's motion for summary judgment against NRG in the pre-SMD congestion litigation.  In this decision, the court concluded that NRG was contractually obligated to pay for congestion charges imposed during the term of the October 29, 1999 standard offer service wholesale sales agreement between CL&P and NRG and found in favor of CL&P and against NRG on each of NRG's four counterclaims.  NRG did not appeal the judgment and the matter is closed.  


While it is unable to determine the ultimate outcome of the two remaining issues, management does not expect their resolution will have a material adverse effect on NU's consolidated net income, financial position or cash flows.  


C.

Long-Term Contractual Arrangements (CL&P, PSNH, Select Energy)


CL&P:  These amounts represent commitments for various services and materials associated with the Middletown to Norwalk, Glenbrook Cables and the Norwalk to Northport-Long Island, New York transmission projects and other projects as of September 30, 2007:


(Millions of Dollars)

 

2007

 

2008

 

2009

 

2010

 

2011

 

Thereafter

 

Total

Transmission segment
 project commitments

 


$


199.3 

 


$


399.6 

 


$


28.9 



$


 


$


 


$


 


$


627.8 


In May of 2007, CL&P and UI entered into a 15-year agreement beginning in 2010 to purchase energy, capacity and renewable energy credits from a biomass energy plant yet to be built.  The agreement has been approved by the DPUC.  CL&P's payments under this agreement will depend on the quantities purchased and the price of energy, and are currently estimated to be approximately $15 million annually from 2010 to 2024 before the reduction for UI's share under a sharing agreement signed and filed with the DPUC.  Under this agreement, CL&P and UI will share the costs and benefits of the contract, with 80 percent to CL&P and 20 percent to UI.  


PSNH:  PSNH has entered into various arrangements for the purchase of wood, coal and transportation services for fuel supply for its electric generating assets.  These purchase commitments at September 30, 2007 are as follows:


(Millions of Dollars)

 

2007

 

2008

 

2009

 

2010

 

2011

 

Thereafter

 

Total

Wood, coal and
  transportation contracts

 


$


29.0 

 


$


101.8 

 


$


57.0 

 


$


44.2 

 


$


31.3 

 


$


3.1 

 


$


266.4 




18


Select Energy: Select Energy maintains long-term agreements to purchase energy as part of its portfolio of resources to meet its actual or expected sales commitments.  Most purchase commitments are recorded at their mark-to-market value as derivative assets and liabilities on the condensed consolidated balance sheets with the exception of one non-derivative contract which is accounted for on the accrual basis.  These purchase commitments at September 30, 2007 are as follows:


(Millions of Dollars)

 

2007

 

2008

 

2009

 

2010

 

2011

 

Thereafter

 

Total

Select Energy
  purchase commitments

 


$


100.3 

 


$


193.3 

 


$


29.7 

 


$


32.1 

 


$


31.2 

 


$


84.8 

 


$


471.4 


Select Energy's purchase commitment amounts exceed the amount expected to be reported in fuel, purchased and net interchange power because many wholesale sales transactions are also classified in fuel, purchased and net interchange power, and certain purchases are included in revenues.  


The amounts and timing of the costs associated with Select Energy's purchase agreements may be impacted by the exit from the NU Enterprises' businesses.


D.

Environmental Matters (HWP)


The company remains in the process of evaluating additional potential remediation requirements at a river site in Massachusetts containing tar deposits.  HWP is at least partially responsible for this site, and substantial remediation activities at this site have already been conducted.  HWP first established a reserve for this site in 1994.  Since that time, HWP has expensed approximately $13 million, of which $12.4 million has been spent and $0.6 million remains in the reserve.  HWP's reserve is based on its most recent site assessment and estimate of required remediation costs.  The ultimate remediation requirements will depend, among other things, on the level and extent of the remaining tar required to be removed, and the extent of HWP’s responsibility.  These matters are the subject of ongoing discussions with the Massachusetts Department of Environmental Protection and may change from time-to-time.  HWP's share of the remediation costs related to this site is not recoverable from ratepayers.  At this time, management cannot predict the outcome of this matter or its ultimate effect on NU.  Any additional increase to the environmental remediation reserve for this site would be recorded in earnings in future periods when it is reasonably estimable and probable, and potential increases may be material.  There were no changes to the environmental reserve for this site in the third quarter of 2007.


E.

Consolidated Edison, Inc. Merger Litigation (NU)


Certain gain and loss contingencies exist with regard to the merger agreement between NU and Consolidated Edison, Inc. (Con Edison) and the related litigation.  


In 2001, Con Edison advised NU that it was unwilling to close its merger with NU on the terms set forth in the parties' 1999 merger agreement (Merger Agreement).  In March of 2001, NU filed suit against Con Edison seeking damages in excess of $1 billion.  


In a 2005 opinion, a panel of three judges at the Second Circuit held that the shareholders of NU had no right to sue Con Edison for its alleged breach of the parties' Merger Agreement.  This ruling left intact the remaining claims between NU and Con Edison for breach of contract, which include NU's claim for recovery of costs and expenses of approximately $32 million and Con Edison's claim for damages of "at least $314 million."  NU's request for a rehearing was denied in 2006.  NU opted not to seek review of this ruling by the United States Supreme Court.  In April of 2006, NU filed its motion for partial summary judgment on Con Edison's damage claim.  NU's motion asserts that NU is entitled to a judgment in its favor with respect to this claim based on the undisputed material facts and applicable law.  The matter is fully briefed and awaiting a decision.  At this time, NU cannot predict the outcome of this matter or its ultimate effect on NU.




19


F.

Guarantees and Indemnifications (All Companies)


NU provides credit assurances on behalf of subsidiaries in the form of guarantees and letters of credit (LOCs) in the normal course of business.  In addition, NU has provided guarantees and various indemnifications on behalf of external parties as a result of the sales of SESI, the retail marketing business and the competitive generation business.  The following table summarizes NU's maximum exposure at September 30, 2007, in accordance with FIN 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," expiration dates, and fair value of amounts recorded.  





Company

 




Description

 


Maximum
Exposure
(in millions)

 

 



Expiration
Date(s)

 

Fair Value
of Amounts
Recorded
(in millions)

On behalf of external parties:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SESI

 

General indemnifications in connection with the sale of SESI including completeness and accuracy of information provided, compliance with laws, and various claims

 

Not Specified 

(1)

 

None

 

$  -

 

 

 

 

 

 

 

 

 

 

 

 

Specific indemnifications in connection with the sale of SESI for estimated costs to complete or modify specific projects

 

Not Specified 

(1)

 

Through project completion

 

0.2

 

 

 

 

 

 

 

 

 

 

 

 

Indemnifications to lenders for payment of shortfalls in the event of early termination of government contracts

 

$2.3 

 

 

2017-2018

 

0.1

 

 

 

 

 

 

 

 

 

 

 

 

Surety bonds covering certain projects

 

$79.8 

 

 

Through project
completion (2)

 

-

 

 

 

 

 

 

 

 

 

 

Hess (Retail Marketing Business)

 

General indemnifications in connection with the sale including compliance with laws, validity of contract information, completeness and accuracy of information provided, absence of default on contracts, and various claims

 

Not Specified 

(1)

 

None

 

-

 

 

 

 

 

 

 

 

 

 

ECP (Competitive Generation Business)

 

General indemnifications in connection with the sale of NGC and the generating assets of Mt. Tom including compliance with laws, validity of contract information, completeness and accuracy of information provided, absence of default on contracts, and various claims

 

Not Specified 

(1)

 

None

 

-

On behalf of subsidiaries:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Regulated Companies

 

Surety bonds, primarily for self-insurance

 

$15.3 

 

 

None

 

N/A

 

 

Letters of credit

 

$28.0 

 

 

2007-2008

 

N/A

 

 

 

 

 

 

 

 

 

 

Rocky River Realty Company

 

Lease payments for real estate

 

$11.2 

 

 

2024

 

N/A

 

 

 

 

 

 

 

 

 

 

NUSCO

 

Lease payments for fleet of vehicles

 

$9.6 

 

 

None

 

N/A

 

 

 

 

 

 

 

 

 

 

SECI-CT and Boulos

 

Surety bonds covering ongoing projects

 

$69.0 

 

 

Through project
completion

 

N/A

 

 

 

 

 

 

 

 

 

 

NGS

 

Performance guarantee and insurance bonds

 

$23.9 

(3)

 

2020 (3)

 

N/A

 

 

 

 

 

 

 

 

 

 

Select Energy

 

Performance guarantees and surety bonds for retail marketing contracts

 

$5.4 

(4)

 

None (5)

 

N/A

 

 

 

 

 

 

 

 

 

 

 

 

Performance guarantees for wholesale contracts

 

$66.6 

(4)

 

2013

 

N/A

 

 

 

 

 

 

 

 

 

 

 

 

Letters of credit

 

$7.0 

 

 

2007

 

N/A

 

 

 

 

 

 

 

 

 

 

HWP

 

Performance and payment guarantee related to coal purchase contract

 

Not Specified 

(6)

 

2009

 

N/A


(1)

There is no specified maximum exposure included in the related sale agreements.  For retail marketing business guarantees, all claims are subject to a $0.3 million threshold.


(2)

The company expects appropriate acknowledgment of project completion for the majority of these surety bonds by the end of the first quarter of 2008.  In October of 2007, $2.6 million of these bonds were removed from the maximum exposure amount.



20


(3)

Included in the maximum exposure is $22.7 million related to a performance guarantee of NGS's obligations for which there is no specified maximum exposure in the agreement.  The maximum exposure is calculated as of September 30, 2007 based on limits of NGS's liability contained in the underlying service contract and assumes that NGS will perform under that contract through its expiration in 2020.  The remaining $1.2 million of maximum exposure relates to insurance bonds with no expiration date which are billed annually on their anniversary date.


(4)

Maximum exposure is as of September 30, 2007; however, exposures vary with underlying commodity prices and for certain contracts are essentially unlimited.  The performance guarantees for the wholesale contracts are expected to expire in 2013.


(5)

NU does not currently anticipate that these remaining guarantees on behalf of Select Energy will result in significant guarantees of the performance of Hess.


(6)

There is no specified maximum exposure included in this guarantee agreement.  NU has guaranteed the performance of HWP under a back-to-back agreement with Energy Capital Partners (ECP) relating to an HWP coal supply contract.  The maximum exposure to loss under very unlikely circumstances is estimated at approximately $46.6 million at September 30, 2007.  NU would have recourse to ECP for approximately $35 million, of which $2 million is secured by an LOC.    


Several underlying contracts that NU guarantees, as well as certain surety bonds, contain credit ratings triggers that would require NU to post collateral in the event that NU's credit ratings are downgraded below investment grade.  


In July of 2006, under its former SESI guarantee, NU was required to purchase contract payments relating to the only guaranteed SESI project that was financed and behind schedule.  Through September 30, 2007, NU has recorded a $0.5 million loss to reduce the carrying value of the contract payments purchased to the amount expected to be received from refinancing through SESI's completion of the project.  The carrying value of these assets is $8.8 million at September 30, 2007 and is included in other deferred debits on the accompanying condensed consolidated balance sheets.  NU may record additional losses associated with this transaction, the amount of which will depend on changes in interest rates used to determine SESI's refinancing proceeds, the amount of project cash available to offset NU's costs, and other factors.  


G.

Transmission Rate Matters and FERC Regulatory Issues (CL&P, PSNH, WMECO)


Pursuant to an October 31, 2006 FERC return on equity (ROE) decision, the New England transmission owners submitted a compliance filing that calculated the refund amounts for transmission customers for the February 1, 2005 to October 31, 2006 time period.  Subsequently, on July 26, 2007, the FERC disagreed with the ROEs the transmission owners used in their refund calculations for the 15-month period between June 3, 2005 and September 3, 2006, rejected a portion of the compliance filing, and required another compliance filing within 30 days.  On August 27, 2007, NU and the other New England transmission owners filed a revised compliance filing which outlined the regional refund process to comply with the FERC's July 26, 2007 order.  In addition, the transmission owners filed a request for rehearing on the issue of the last clean rate doctrine for the period from June 3, 2005 to September 3, 2006.  NU is awaiting a final FERC determination on this issue.


NU's transmission companies currently estimate additional related pre-tax refunds to be $3.4 million (approximately $2 million after-tax).  NU's distribution companies would receive a net after-tax benefit of approximately $0.3 million as a result of these refunds.  The additional estimated refunds and benefits totaling $1.7 million after-tax were recorded in the third quarter of 2007.  




21


7.

COMPREHENSIVE INCOME (NU, CL&P, PSNH, WMECO, NU Enterprises, Yankee Gas)


Total comprehensive income, which includes all comprehensive income/(loss) items by category, for the three and nine months ended September 30, 2007 and 2006 is as follows:


 

 

Three Months Ended September 30, 2007


(Millions of Dollars)

 


NU*

 


CL&P

 


PSNH

 


WMECO

 

NU
Enterprises

 

Yankee
Gas

 


Other

Net income/(loss)

 

$

50.2 

 

$

33.6 

 

$

13.0 

 

$

5.3 

 

$

0.7 

 

$

(3.4)

 

$

1.0 

Comprehensive (loss)/income items:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Qualified cash flow hedging items

 

 

(5.2)

 

 

(4.6)

 

 

 

 

(0.6)

 

 

 

 

 

 

  Unrealized losses on securities

 

 

(0.7)

 

 

 

 

 

 

(0.1)

 

 

 

 

 

 

(0.6)

  Pension, SERP, and other
    postretirement benefits

 

 


1.7 

 

 


 

 


 

 


 

 


5.6 

 

 


 

 


(3.9)

Net change in comprehensive
  (loss)/income items

 

 


(4.2)

 

 


(4.6)

 

 


 

 


(0.7)

 

 


5.6 

 

 


 

 


(4.5)

Total comprehensive income/(loss)

 

$

46.0 

 

$

29.0 

 

$

13.0 

 

$

4.6 

 

$

6.3 

 

$

(3.4)

 

$

(3.5)


 

 

Three Months Ended September 30, 2006


(Millions of Dollars)

 


NU*

 


CL&P

 


PSNH

 


WMECO

 

NU
Enterprises

 

Yankee
Gas

 


Other

Net income/(loss)

 

$

111.5 

 

$

99.6 

 

$

7.9 

 

$

3.7 

 

$

3.2 

 

$

(5.3)

 

$

2.4 

Comprehensive loss items:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Unrealized losses on securities

 

 

(0.9)

 

 

 

 

(0.1)

 

 

(0.1)

 

 

 

 

 

 

(0.7)

Net change in comprehensive loss items

 

 

(0.9)

 

 

 

 

(0.1)

 

 

(0.1)

 

 

 

 

 

 

(0.7)

Total comprehensive income/(loss)

 

$

110.6 

 

$

99.6 

 

$

7.8 

 

$

3.6 

 

$

3.2 

 

$

(5.3)

 

$

1.7 


 

 

Nine Months Ended September 30, 2007


(Millions of Dollars)

 


NU*

 


CL&P

 


PSNH

 


WMECO

 

NU
Enterprises

 

Yankee
Gas

 


Other

Net income

 

$

173.8 

 

$

91.6 

 

$

38.2 

 

$

16.8 

 

$

8.1 

 

$

10.5 

 

$

8.6 

Comprehensive (loss)/income items:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Qualified cash flow hedging instruments

 

 

(6.8)

 

 

(6.2)

 

 

 

 

(0.7)

 

 

 

 

 

 

0.1 

  Unrealized gains/(losses) on securities

 

 

0.6 

 

 

 

 

 

 

(0.1)

 

 

 

 

 

 

0.7 

  Pension, SERP, and other
    postretirement benefits

 

 


8.0 

 

 


 

 


 

 


 

 


9.4 

 

 


 

 


(1.4)

Net change in comprehensive
  income/(loss) items

 

 


1.8 

 

 


(6.2)

 

 


 

 


(0.8)

 

 


9.4 

 

 


 

 


(0.6)

Total comprehensive income

 

$

175.6 

 

$

85.4 

 

$

38.2 

 

$

16.0 

 

$

17.5 

 

$

10.5 

 

$

8.0 


 

 

Nine Months Ended September 30, 2006


(Millions of Dollars)

 


NU*

 


CL&P

 


PSNH

 


WMECO

 

NU
Enterprises

 

Yankee
Gas

 


Other

Net income/(loss)

 

$

123.6 

 

$

148.2 

 

$

27.9 

 

$

11.5 

 

$

(73.7)

 

$

6.4 

 

$

3.3 

Comprehensive income/(loss) items:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Qualified cash flow hedging instruments

 

 

13.2 

 

 

(4.6)

 

 

 

 

0.1 

 

 

17.8 

 

 

 

 

(0.1)

  Unrealized losses on securities

 

 

(1.0)

 

 

 

 

(0.1)

 

 

(0.2)

 

 

 

 

 

 

(0.7)

  Other

 

 

2.3 

 

 

 

 

 

 

 

 

 

 

 

 

2.3 

Net change in comprehensive
  income/(loss) items

 

 


14.5 

 

 


(4.6)

 

 


(0.1)

 

 


(0.1)

 

 


17.8 

 

 


 

 


1.5 

Total comprehensive income/(loss)

 

$

138.1 

 

$

143.6 

 

$

27.8 

 

$

11.4 

 

$

(55.9)

 

$

6.4 

 

$

4.8 


*After preferred dividends of subsidiary.


Comprehensive income amounts included in the Other column primarily relate to NU parent and Northeast Utilities Service Company (NUSCO).




22


Accumulated other comprehensive income fair value adjustments in NU's qualified cash flow hedging instruments for the nine months ended September 30, 2007 and the twelve months ended December 31, 2006 are as follows:



(Millions of Dollars, Net of Tax)

 

Nine Months Ended
September 30, 2007

 

Twelve Months Ended
December 31, 2006

Balance at beginning of period

 

$

5.9 

 

$

18.2 

Hedged transactions recognized into earnings

 

 

0.1 

 

 

2.3 

Amount reclassified into earnings due to
  discontinuation of cash flow hedges

 

 


 

 


(14.1)

Change in fair value of hedged
 transactions delivered

 

 


 

 


(4.5)

Cash flow transactions entered into for the period

 

 

(6.9)

 

 

4.0 

Net change associated with the current period
  hedging transactions

 

 


(6.8)

 

 


(12.3)

Total fair value adjustments included in accumulated
  other comprehensive income

 


$


(0.9)

 


$


5.9 


In the first quarter of 2006, $14.1 million was reclassified from accumulated other comprehensive income into earnings (included in other operation expenses) due to discontinuing cash flow hedge accounting and the conclusion that the retail marketing contracts hedged beyond June 1, 2006 were no longer probable of physical delivery due to the retail business being sold.  


In March of 2006, CL&P entered into a forward lock agreement to hedge the interest rate associated with $125 million of its $250 million, 30-year fixed rate long-term debt issuance.  Under the agreement, CL&P locked in a LIBOR swap rate of 5.322 percent based on the notional amount of $125 million in long-term debt that was issued in June of 2006.  On June 1, 2006, the hedge was settled, and a net of tax charge of $4.6 million, ($7.8 million pre-tax), was recorded in accumulated other comprehensive income to be amortized into earnings over the term of the long-term debt.  


In February of 2007, CL&P entered into two forward lock agreements to hedge the interest rates associated with $75 million of its $150 million, 10-year fixed rate long-term debt issuance and with $75 million of its $150 million, 30-year fixed rate long-term debt issuance.  Under the agreements, CL&P locked in a LIBOR swap rate of 5.229 percent for the 10-year hedge and 5.369 percent for the 30-year hedge, both based on the notional amounts of $75 million in long-term debt that was issued in March of 2007.  On March 27, 2007, the hedge was settled and a net-of-tax charge of $1.6 million ($2.6 million pre-tax), was recorded in accumulated other comprehensive income to be amortized into earnings over the terms of the long-term debt.


In July of 2007, CL&P entered into two forward lock agreements to hedge the interest rates associated with $50 million of its $100 million, 10-year fixed rate long-term debt issuance and with $50 million of its $100 million, 30-year fixed rate long-term debt issuance.  Under the agreements, CL&P locked in a LIBOR swap rate of 5.718 percent for the 10-year hedge and 5.865 percent for the 30-year hedge, both based on the notional amounts of $50 million in long-term debt that was issued in July of 2007.  On July 16, 2007, the hedge was settled and a net-of-tax charge of $4.7 million ($7.7 million pre-tax), was recorded in accumulated other comprehensive income to be amortized into earnings over the terms of the long-term debt.  In addition, a net of tax charge of $67,000 ($110,000 pre-tax) was recorded related to ineffectiveness incurred upon termination of the hedge.


Also, in July of 2007, WMECO entered into a forward lock agreement to hedge the interest rate associated with its $40 million, 30-year fixed rate long-term debt issuance.  Under the agreement, WMECO locked in a LIBOR swap rate of 5.882 percent based on the notional amount of $40 million in long-term debt that was issued in July of 2007.  On August 15, 2007, the hedge was settled and a net-of-tax charge of $0.6 million ($1 million pre-tax), was recorded in accumulated other comprehensive income to be amortized into earnings over the term of the long-term debt.


It is estimated that a charge of $192,000 will be reclassified as a decrease to earnings over the next twelve months, as a result of amortization of the interest rate locks.


Accumulated other comprehensive income items unrelated to NU's cash flow hedging instruments totaled a positive $7.2 million and a negative $1.4 million at September 30, 2007 and December 31, 2006, respectively.  These amounts relate to net unrealized gains on investments in marketable debt and equity securities and amounts recorded for pension, supplemental executive retirement plan (SERP) and other postretirement benefits, net of related income taxes related to the implementation of SFAS No. 158, "Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans."


At September 30, 2007, it is estimated that a pre-tax $0.6 million included in the accumulated other comprehensive income balance will be reclassified as a decrease to earnings in the next year related to pension, SERP and other postretirement benefits adjustments.  




23


8.

EARNINGS PER SHARE (NU)


Earnings per share (EPS) is computed based upon the weighted average number of common shares outstanding, excluding unallocated Employee Stock Ownership Plan (ESOP) shares, during each period.  Diluted EPS is computed on the basis of the weighted-average number of common shares outstanding plus the potential dilutive effect if certain securities are converted into common stock.  The following table excludes 152,050 options for the nine months ended September 30, 2006, as these options were antidilutive.  There were no antidilutive options for the three months ended September 30, 2006 or the three and nine months ended September 30, 2007.  The following table sets forth the components of basic and fully diluted EPS:


 

 

For the Three Months Ended September 30,

 

For the Nine Months Ended September 30,

(Millions of Dollars, Except for Share Information)

 

2007

 

2006

 

2007

 

2006

Income from continuing operations

 

$

50.2 

 

$

102.7 

 

$

172.6 

 

$

96.3 

Income from discontinued operations

 

 

 

 

8.8 

 

 

1.2 

 

 

27.3 

Net income

 

$

50.2 

 

$

111.5 

 

$

173.8 

 

$

123.6 

Basic EPS common shares outstanding (average)

 

 

154,930,930 

 

 

153,883,480 

 

 

154,672,270 

 

 

153,651,610 

Dilutive effect

 

 

489,309 

 

 

437,195 

 

 

538,434 

 

 

385,160 

Fully diluted EPS common shares
  outstanding (average)

 




155,420,239 

 

 


154,320,675 

 

 


155,210,704 

 

 


154,036,770 

Basic and Fully Diluted EPS:

 

 

 

 

 

 

 

 

 

 

 

 

  Income from continuing operations

 

$

0.32 

 

$

0.67 

 

$

1.12 

 

$

0.63 

  Income from discontinued operations

 

 

 

 

0.05 

 

 

 

 

0.17 

Basic and fully diluted EPS  

 

$

0.32 

 

$

0.72 

 

$

1.12 

 

$

0.80 


Restricted share units (RSUs) are included in basic common shares outstanding when shares are both vested and issued.  The dilutive effect of RSUs granted but not issued is calculated using the treasury stock method.  Assumed proceeds of RSUs 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 difference between the market value of RSUs outstanding but not issued using the average market price during the period and the grant date market value.  


The dilutive effect of stock options is also calculated using the treasury stock method.  Assumed proceeds for stock options consist of remaining compensation cost to be recognized, 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 difference between the market value of the average stock options outstanding for the period using the average market price and the grant price.  


Allocated ESOP shares are included in basic common shares outstanding in the previous table.  


9.

PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS (All Companies)


NU's subsidiaries participate in a uniform noncontributory defined benefit retirement plan (Pension Plan) covering substantially all regular NU employees and also provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees (PBOP Plan).  In addition, NU maintains a SERP which provides benefits to eligible participants, who are officers of NU, that would have been provided to them under NU’s Pension Plan if certain Internal Revenue Code and other limitations were not imposed.  


NU estimated the December 31, 2006 prepaid or accrued PBOP Plan asset or obligation based on an actuarial valuation as of the beginning of the year (January 1, 2006), adjusted for known changes during the year such as actual earnings, interest rate levels, expenses incurred and benefits paid during the year.  The estimated December 31, 2006 balance was also used to estimate the related 2007 PBOP Plan income or expense and the prepaid or accrued PBOP Plan asset or obligation recorded through the second quarter of 2007.  The December 31, 2006 year end estimates were adjusted and recorded in the third quarter of 2007 based on an actuarial valuation using actual data as of January 1, 2007.  The actuarial valuation resulted in a decrease to the accrued PBOP Plan liability of $14.5 million with a decrease to the regulatory asset for deferred benefits of $13 million and an increase to accumulated other comprehensive income of approximately $0.9 million, net of tax.  


The pre-tax, pre-capitalization earnings impact of this change in estimate is to decrease annual 2007 PBOP Plan expense by approximately $1.4 million.  




24


The components of net periodic benefit expense/(income) for the Pension Plan, PBOP Plan and SERP for the three and nine months ended September 30, 2007 and 2006 are as follows:


NU

 

For the Three Months Ended September 30,

 

 

Pension Benefits

 

Postretirement Benefits

 

SERP Benefits

(Millions of Dollars)

 

2007

 

2006

 

2007

 

2006

 

2007

 

2006

Service cost

 

$

11.4 

 

$

12.4 

 

$

1.6 

 

$

2.1 

 

$

0.2 

 

$

0.3 

Interest cost

 

 

33.7 

 

 

33.1 

 

 

6.2 

 

 

6.8 

 

 

0.5 

 

 

0.5 

Expected return on plan assets

 

 

(48.4)

 

 

(43.8)

 

 

(4.6)

 

 

(3.5)

 

 

 

 

Amortization of unrecognized net
  transition obligation

 

 


 

 


 

 


3.2 

 

 


3.1 

 

 


 

 


Amortization of prior service cost

 

 

2.5 

 

 

1.8 

 

 

(0.1)

 

 

(0.1)

 

 

 

 

Amortization of actuarial loss

 

 

4.1 

 

 

10.9 

 

 

2.9 

 

 

4.4 

 

 

0.2 

 

 

0.2 

Net periodic expense - before curtailments
  and termination benefits

 

 


3.3 

 

 


14.4 

 

 


9.2 

 

 


12.8 

 

 


0.9 

 

 


1.0 

Curtailments

 

 

 

 

(4.2)

 

 

 

 

(1.5)

 

 

 

 

Termination benefits

 

 

(0.3)

 

 

(0.7)

 

 

 

 

(0.2)

 

 

 

 

Total curtailments and termination benefits

 

 

(0.3)

 

 

(4.9)

 

 

 

 

(1.7)

 

 

 

 

Total - net periodic expense

 

$

3.0 

 

$

9.5 

 

$

9.2 

 

$

11.1 

 

$

0.9 

 

$

1.0 


NU

 

For the Nine Months Ended September 30,

 

 

Pension Benefits

 

Postretirement Benefits

 

SERP Benefits

(Millions of Dollars)

 

2007

 

2006

 

2007

 

2006

 

2007

 

2006

Service cost

 

$

35.7 

 

$

37.0 

 

$

5.8 

 

$

6.2 

 

$

0.6 

 

$

0.8 

Interest cost

 

 

102.8 

 

 

96.6 

 

 

19.5 

 

 

20.5 

 

 

1.5 

 

 

1.5 

Expected return on plan assets

 

 

(146.8)

 

 

(130.2)

 

 

(13.7)

 

 

(10.5)

 

 

 

 

Amortization of unrecognized net
  transition obligation/(asset)

 

 


0.1 

 

 


(0.1)

 

 


9.0 

 

 


8.6 

 

 


 

 


Amortization of prior service cost

 

 

6.4 

 

 

4.8 

 

 

(0.2)

 

 

(0.2)

 

 

0.1 

 

 

0.1 

Amortization of actuarial loss

 

 

15.9 

 

 

30.3 

 

 

8.7 

 

 

13.4 

 

 

0.5 

 

 

0.7 

Net periodic expense - before curtailments
  and termination benefits

 

 


14.1 

 

 


38.4 

 

 


29.1 

 

 


38.0 

 

 


2.7 

 

 


3.1 

Curtailments

 

 

 

 

(4.9)

 

 

 

 

(2.1)

 

 

 

 

Termination benefits

 

 

(0.3)

 

 

 

 

 

 

0.3 

 

 

 

 

Total curtailments and termination benefits

 

 

(0.3)

 

 

(4.9)

 

 

 

 

(1.8)

 

 

 

 

Total - net periodic expense

 

$

13.8 

 

$

33.5 

 

$

29.1 

 

$

36.2 

 

$

2.7 

 

$

3.1 




25


A portion of these pension amounts is capitalized related to current employees that are working on capital projects.  Amounts capitalized were approximately $0.4 million and a de minimis amount for the three and nine months ended September 30, 2007, respectively, and $7.7 million and $12.9 million for the three  and nine months ended September 30, 2006, respectively.  The amounts for the three and nine months ended September 30, 2007 offset capital costs, as pension income was recorded for those periods for certain of NU's subsidiaries.


CL&P

 

For the Three Months Ended September 30,

 

 

Pension Benefits

 

Postretirement Benefits

 

SERP Benefits

(Millions of Dollars)

 

2007

 

2006

 

2007

 

2006

 

2007

 

2006

Service cost

 

$

3.9 

 

$

4.2 

 

$

0.5 

 

$

0.7 

 

$

 

$

Interest cost

 

 

12.1 

 

 

12.1 

 

 

2.4 

 

 

2.8 

 

 

 

 

0.1 

Expected return on plan assets

 

 

(22.5)

 

 

(20.4)

 

 

(1.8)

 

 

(1.4)

 

 

 

 

Amortization of unrecognized net
  transition obligation

 

 


 

 


 

 


1.2 

 

 


1.7 

 

 


 

 


Amortization of prior service cost

 

 

1.0 

 

 

0.8 

 

 

 

 

 

 

 

 

Amortization of actuarial loss

 

 

1.2 

 

 

4.1 

 

 

1.5 

 

 

1.7 

 

 

0.1 

 

 

Net periodic (income)/expense -
  before curtailments and termination benefits

 

 


(4.3)

 

 


0.8 

 

 


3.8 

 

 


5.5 

 

 


0.1 

 

 


0.1 

Curtailments

 

 

 

 

(1.0)

 

 

 

 

(0.8)

 

 

 

 

Termination benefits

 

 

 

 

(0.4)

 

 

 

 

 

 

 

 

Total curtailments and termination benefits

 

 

 

 

(1.4)

 

 

 

 

(0.8)

 

 

 

 

Total - net periodic (income)/expense

 

$

(4.3)

 

$

(0.6)

 

$

3.8 

 

$

4.7 

 

$

0.1 

 

$

0.1 


CL&P

 

For the Nine Months Ended September 30,

 

 

Pension Benefits

 

Postretirement Benefits

 

SERP Benefits

(Millions of Dollars)

 

2007

 

2006

 

2007

 

2006

 

2007

 

2006

Service cost

 

$

12.2 

 

$

12.8 

 

$

1.9 

 

$

2.1 

 

$

 

$

Interest cost

 

 

36.8 

 

 

35.9 

 

 

7.6 

 

 

8.3 

 

 

0.1 

 

 

0.2 

Expected return on plan assets

 

 

(68.2)

 

 

(61.0)

 

 

(5.4)

 

 

(4.1)

 

 

 

 

Amortization of unrecognized net
  transition obligation

 

 


 

 


 

 


4.3 

 

 


4.6 

 

 


 

 


Amortization of prior service cost

 

 

2.8 

 

 

2.0 

 

 

 

 

 

 

 

 

Amortization of actuarial loss

 

 

5.1 

 

 

11.9 

 

 

3.8 

 

 

5.3 

 

 

0.1 

 

 

0.1 

Net periodic (income)/expense -
  before curtailments and termination benefits

 

 


(11.3)

 

 


1.6 

 

 


12.2 

 

 


16.2 

 

 


0.2 

 

 


0.3 

Curtailments

 

 

 

 

(1.3)

 

 

 

 

(1.4)

 

 

 

 

Termination benefits

 

 

 

 

(0.8)

 

 

 

 

(0.1)

 

 

 

 

Total curtailments and termination benefits

 

 

 

 

(2.1)

 

 

 

 

(1.5)

 

 

 

 

Total - net periodic (income)/expense

 

$

(11.3)

 

$

(0.5)

 

$

12.2 

 

$

14.7 

 

$

0.2 

 

$

0.3 


Not included in the pension (income)/expense amounts above are intercompany allocations totaling $2.6 million and $8.6 million for the three and nine months ended September 30, 2007, respectively, and $2.7 million and $8.8 million for the three and nine months ended September 30, 2006, respectively.  Intercompany allocations of postretirement benefits totaled $1.9 million and $5.5 million for the three and nine months ended September 30, 2007, respectively, and $1.7 million and $5.6 million for the three and nine months ended September 30, 2006, respectively.  Intercompany allocations of SERP benefits totaled $0.5 million and $1.4 million for the three and nine months ended September 30, 2007, respectively, and $0.5 million and $1.5 million for the three and nine months ended September 30, 2006, respectively


For CL&P, a portion of the pension amounts, including intercompany allocations, is capitalized related to current employees that are working on capital projects.  Amounts capitalized were $1.3 million and $3.2 million for the three and nine months ended September 30, 2007, respectively, and $3 million and $4.4 million for the three and nine months ended September 30, 2006, respectively.  The amounts for the three and nine months ended September 30, 2007 offset capital costs, as pension income was recorded for those periods.



26



PSNH

 

For the Three Months Ended September 30,

 

 

Pension Benefits

 

Postretirement Benefits

 

SERP Benefits

(Millions of Dollars)

 

2007

 

2006

 

2007

 

2006

 

2007

 

2006

Service cost

 

$

2.3 

 

$

2.4 

 

$

0.4 

 

$

0.5 

 

$

 

$

Interest cost

 

 

5.3 

 

 

5.2 

 

 

1.2 

 

 

1.2 

 

 

0.1 

 

 

Expected return on plan assets

 

 

(4.4)

 

 

(4.2)

 

 

(0.8)

 

 

(0.6)

 

 

 

 

Amortization of unrecognized net
  transition obligation

 

 


0.1 

 

 


0.1 

 

 


0.6 

 

 


0.6 

 

 


 

 


Amortization of prior service cost

 

 

0.5 

 

 

0.4 

 

 

 

 

 

 

 

 

Amortization of actuarial loss

 

 

0.9 

 

 

1.7 

 

 

0.6 

 

 

0.8 

 

 

 

 

0.1 

Net periodic expense - before curtailments
  and termination benefits

 

 


4.7 

 

 


5.6 

 

 


2.0 

 

 


2.5 

 

 


0.1 

 

 


0.1 

Curtailments

 

 

 

 

(0.7)

 

 

 

 

(0.1)

 

 

 

 

Termination benefits

 

 

 

 

(0.1)

 

 

 

 

 

 

 

 

Total curtailments and termination benefits

 

 

 

 

(0.8)

 

 

 

 

(0.1)

 

 

 

 

Total - net periodic expense

 

$

4.7 

 

$

4.8 

 

$

2.0 

 

$

2.4 

 

$

0.1 

 

$

0.1 


PSNH

 

For the Nine Months Ended September 30,

 

 

Pension Benefits

 

Postretirement Benefits

 

SERP Benefits

(Millions of Dollars)

 

2007

 

2006

 

2007

 

2006

 

2007

 

2006

Service cost

 

$

7.3 

 

$

7.2 

 

$

1.3 

 

$

1.3 

 

$

 

$

Interest cost

 

 

16.3 

 

 

15.2 

 

 

3.6 

 

 

3.7 

 

 

0.1

 

 

0.1 

Expected return on plan assets

 

 

(13.4)

 

 

(12.3)

 

 

(2.5)

 

 

(1.9)

 

 

 

 

Amortization of unrecognized net
  transition obligation

 

 


0.2 

 

 


0.2 

 

 


1.8 

 

 


1.9 

 

 


 

 


Amortization of prior service cost

 

 

1.3 

 

 

1.0 

 

 

 

 

 

 

 

 

Amortization of actuarial loss

 

 

3.1 

 

 

4.6 

 

 

1.7 

 

 

2.5 

 

 

0.2 

 

 

0.1 

Net periodic expense - before curtailments
  and termination benefits

 

 


14.8 

 

 


15.9 

 

 


5.9 

 

 


7.5 

 

 


0.3 

 

 


0.2 

Curtailments

 

 

 

 

(0.6)

 

 

 

 

0.1 

 

 

 

 

Termination benefits

 

 

 

 

 

 

 

 

 

 

 

 

Total curtailments and termination benefits

 

 

 

 

(0.6)

 

 

 

 

0.1 

 

 

 

 

Total - net periodic expense

 

$

14.8 

 

$

15.3 

 

$

5.9 

 

$

7.6 

 

$

0.3 

 

$

0.2 


Not included in the pension expense amounts above are intercompany allocations totaling $0.4 million and $1.4 million for the three and nine months ended September 30, 2007, respectively, and $0.4 million and $1.3 million for the three and nine months ended September 30, 2006, respectively.  Intercompany allocations of postretirement benefits totaled $0.3 million and $1 million for both the three and nine months ended September 30, 2007 and 2006, respectively.  Intercompany allocations of SERP benefits totaled $0.1 million and $0.3 million for both the three and nine months ended September 30, 2007 and 2006, respectively.




27


For PSNH, a portion of these pension amounts, including intercompany allocations, is capitalized related to current employees that are working on capital projects.  Amounts capitalized were $1.1 million and $3.6 million for the three and nine months ended September 30, 2007, respectively, and $3.9 million and $7.3 million for the three and nine months ended September 30, 2006, respectively.   


WMECO

 

For the Three Months Ended September 30,

 

For the Nine Months Ended September 30,

 

 

Pension Benefits

 

Postretirement Benefits

 

Pension Benefits

 

Postretirement Benefits

 

 

2007

 

2006

 

2007

 

2006

 

2007

 

2006

 

2007

 

2006

(Millions of Dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Service cost

 

$

0.8 

 

$

0.8 

 

$

0.1 

 

$

0.1 

 

$

2.5 

 

$

2.6 

 

$

0.4 

 

$

0.5 

Interest cost

 

 

2.4 

 

 

2.4 

 

 

0.5 

 

 

0.6 

 

 

7.4 

 

 

7.2 

 

 

1.7 

 

 

1.8 

Expected return on plan assets

 

 

(4.9)

 

 

(4.4)

 

 

(0.4)

 

 

(0.4)

 

 

(15.1)

 

 

(13.4)

 

 

(1.3)

 

 

(1.1)

Amortization of unrecognized net
  transition obligation

 

 


 

 


 

 


0.2 

 

 


0.4 

 

 


 

 


 

 


0.8 

 

 


1.0 

Amortization of prior service cost

 

 

0.2 

 

 

0.2 

 

 

 

 

 

 

0.6 

 

 

0.5 

 

 

 

 

Amortization of actuarial loss

 

 

0.2 

 

 

0.8 

 

 

0.3 

 

 

0.4 

 

 

0.9 

 

 

2.4 

 

 

0.7 

 

 

1.1 

Net periodic (income)/expense -
  before curtailments and
  termination benefits

 

 



(1.3)

 

 



(0.2)

 

 



0.7 

 

 



1.1 

 

 



(3.7)

 

 



(0.7)

 

 



2.3 

 

 



3.3 

Curtailments

 

 

 

 

(0.2)

 

 

 

 

(0.1)

 

 

 

 

(0.2)

 

 

 

 

(0.3)

Termination benefits

 

 

 

 

(0.1)

 

 

 

 

 

 

 

 

(0.2)

 

 

 

 

Total curtailments and
  termination benefits

 

 


 

 


(0.3)

 

 


 

 


(0.1)

 

 


             -  

 

 


(0.4)

 

 


 

 


(0.3)

Total net periodic (income)/expense

 

$

(1.3)

 

$

(0.5)

 

$

0.7 

 

$

1.0 

 

$

(3.7)

 

$

(1.1)

 

$

2.3 

 

$

3.0 


A de minimis amount of SERP expense was recorded for WMECO for the three and nine months ended September 30, 2007 and 2006.  Intercompany allocations of SERP benefits totaled $0.1 and $0.2 million for both the three and nine months ended September 30, 2007 and 2006, respectively.


Not included in the pension income amounts above are intercompany expense allocations totaling $0.4 million and $1.4 million for the three and nine months ended September 30, 2007, respectively, and $0.6 million and $1.6 million for the three and nine months ended September 30, 2006, respectively.  Intercompany allocations of postretirement benefits totaled $0.3 million and $0.9 million for both the three and nine months ended September 30, 2007 and 2006, respectively.  


For WMECO, a portion of these pension amounts, including intercompany allocations, is capitalized related to current employees that are working on capital projects.  Amounts capitalized were $0.4 million and $1.2 million for the three and nine months ended September 30, 2007, respectively, and $0.2 million and $0.1 million for the three and nine months ended September 30, 2006.  The capitalized amounts for 2007 and 2006 offset capital project costs, as pension income was recorded for those periods.  


Curtailment and Termination Benefits:  In December of 2005, a new program was approved allowing then current employees to elect to receive retirement benefits under a new 401(k) benefit rather than under the Pension Plan.  The approval of the new plan resulted in the recording of an estimated pre-capitalization, pre-tax curtailment expense of $6.2 million in 2005, as a certain number of employees were expected to elect the new 401(k) benefit, resulting in a reduction in aggregate estimated future years of service under the Pension Plan.  Because the predicted level of elections of the new benefit did not occur, NU recorded an adjustment to this curtailment in the third quarter of 2006.  This adjustment resulted in a pre-capitalization, pre-tax reduction in the curtailment expense of $3.6 million for NU.


In addition, as a result of its corporate reorganization, NU recorded a combined pre-capitalization, pre-tax curtailment expense and related termination benefits for the Pension Plan totaling $5.5 million in 2005.  Based on a revised estimate of expected head count reductions, NU recorded an adjustment to the curtailment and related termination benefits in the first nine months of 2006.  This adjustment resulted in a combined pre-capitalization, pre-tax reduction in the curtailment expense ($0.6 million) and termination benefits ($0.7 million) totaling $1.3 million for NU.  In addition, NU recorded an additional pre-capitalization, pre-tax reduction in termination benefit expense of $0.3 million in the third quarter of 2007.  


Severance Benefits:  As a result of its corporate reorganization, in 2005 NU recorded severance and termination benefits totaling $14.4 million relating to expected terminations of regulated company and NUSCO employees.  These severance benefits were recorded in other operating expenses because these amounts were for benefits under an existing benefit arrangement.  In 2006, NU updated its prior estimates of regulated company and NUSCO severance benefits and a total reduction in severance and related expenses of $2.4 million was recorded.  This reduction was also included in other operating expenses on the accompanying condensed consolidated statements of income and was primarily due to a reduction in the expected number of terminated regulated company and NUSCO employees.  




28


In the first nine months of 2006, NU recorded $4.1 million for severance and other employee benefits, as these benefits became probable and estimable as a result of the sale of the retail marketing business to Hess.  Of this amount, $0.6 million was for enhanced minimum benefits and was included in restructuring charges, with the remaining $3.5 million included in other operating expenses on the accompanying condensed consolidated statements of income for the nine months ended September 30, 2006 because these amounts were for severance benefits under an existing benefit arrangement.


NU contributed $9.1 million in the third quarter of 2007 and $28.7 million for the nine months ended September 30, 2007 to fund its PBOP Plan.  NU funded an additional $2.5 million to its PBOP Plan with funds received from the federal Medicare subsidy for a portion of its 2006 subsidy.  


10.

SEGMENT INFORMATION (All Companies)


Presentation: NU is organized between the regulated companies and NU Enterprises businesses based on a combination of factors, including the characteristics of each business' products and services, the sources of operating revenues and expenses and the regulatory environment in which each segment operates.  Cash flows for total investments in plant included in the segment information below are cash capital expenditures that do not include cost of removal, AFUDC, and the capitalized portion of pension expense or income.  Segment information for all periods presented has been reclassified to conform to the current period presentation, except as indicated.  


The regulated companies segment, including the electric distribution, generation and transmission segments, as well as the gas distribution segment (Yankee Gas), represents approximately 96 percent of NU's total revenues for both the three and nine months ended September 30, 2007.  Similar amounts for 2006 were 95 percent and 85 percent, respectively.  CL&P's, PSNH's and WMECO's complete condensed consolidated financial statements are included in this combined report on Form 10-Q.  PSNH's distribution segment includes generation activities.  Also included in this combined report on Form 10-Q is detailed information regarding CL&P's, PSNH's, and WMECO's transmission segments.  


At September 30, 2007, the NU Enterprises business segment includes:  1) Select Energy (wholesale contracts), 2) NGS, 3) Boulos, 4) SECI-CT, and 5) NU Enterprises parent.  


Other in the segment tables primarily consists of 1) the results of NU parent, which includes other income related to the equity in earnings of NU parent's subsidiaries and interest income from the NU Money Pool, which are both eliminated in consolidation, and interest income and expense related to the cash and debt of NU parent, respectively, 2) the revenues and expenses of NU's service companies, most of which are eliminated in consolidation, and 3) the results of other subsidiaries, which are comprised of the Rocky River Realty Company and the Quinnehtuk Company (real estate subsidiaries), Mode 1 Communications, Inc. and the results of the non-energy-related subsidiaries of Yankee Energy System, Inc. (Yankee Energy Services Company, Yankee Energy Financial Services Company, and NorConn Properties, Inc.).


Effective on January 1, 2007, financial information for the remaining operations of HWP that were not exited as part of the sale of the competitive generation business was included as part of the Other reportable segment as these operations were no longer considered part of NU Enterprises subsequent to the sale.  Accordingly, HWP’s remaining operations have been presented as part of the Other reportable segment for the three and nine months ended September 30, 2007.


As a result of the sale of NU Enterprises' retail marketing and competitive generation businesses, the financial information used by management was reduced to the remaining wholesale contracts, the operations of the remaining energy services businesses and NU Enterprises parent.  As a result of exiting these businesses in 2006, the operations of NU Enterprises have been aggregated and presented as one reportable segment for the three and nine months ended September 30, 2007 and 2006.


Customer Concentrations:  Select Energy provided basic generation service in the New Jersey market in 2007.  In 2006, Select Energy also provided service in the Maryland market.  Select Energy revenues related to these contracts represented $37.8 million and $96.1 million for the three months ended September 30, 2007 and 2006, respectively, and $145.9 million and $346.6 million for the nine months ended September 30, 2007 and 2006, respectively, of total NU Enterprises' billings.  No other individual customer represented in excess of 10 percent of NU Enterprises' billings for the three and nine months ended September 30, 2007 and 2006.  As these contracts expire, sales under a long-term contract with NYMPA may exceed 10 percent of NU Enterprises' billings in future periods.


Select Energy reported the settlement of all derivative contracts of the wholesale marketing business, including full requirements sales contracts and intercompany revenues, in fuel, purchased and net interchange power.  This presentation is a result of applying mark-to-market accounting to those contracts due to the decision to exit the wholesale marketing business.


Regulated companies 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.



29



NU's segment information for the three and nine months ended September 30, 2007 and 2006 is as follows (some amounts between the financial statements and between segment schedules may not agree due to rounding):


 

 

For the Three Months Ended September 30, 2007

 

 

Regulated Companies

 

 

 

 

Distribution (1)

 

 

 

 

(Millions of Dollars)

 

Electric

 

Gas

 

Transmission

 

NU Enterprises

 

Other

 

Eliminations

 

Total

Operating revenues

 

$

1,243.3 

 

$

71.7 

 

$

72.9 

 

$

68.4 

 

$

93.2 

 

$

(98.4)

 

$

1,451.1 

Depreciation and amortization

 

 

(116.6)

 

 

(6.8)

 

 

(9.6)

 

 

(0.1)

 

 

(2.0)

 

 

1.2 

 

 

(133.9)

Other operating expenses

 

 

(1,043.4)

 

 

(64.3)

 

 

(29.0)

 

 

(66.1)

 

 

(87.6)

 

 

96.5 

 

 

(1,193.9)

Operating income/(loss)

 

 

83.3 

 

 

0.6 

 

 

34.3 

 

 

2.2 

 

 

3.6 

 

 

(0.7)

 

 

123.3 

Interest expense, net of AFUDC

 

 

(43.2)

 

 

(5.1)

 

 

(8.9)

 

 

(1.8)

 

 

(8.3)

 

 

5.6 

 

 

(61.7)

Interest income

 

 

1.0 

 

 

 

 

0.4 

 

 

0.6 

 

 

7.1 

 

 

(5.6)

 

 

3.5 

Other income/(loss), net

 

 

2.9 

 

 

 

 

3.8 

 

 

(0.1)

 

 

27.2 

 

 

(26.5)

 

 

7.3 

Income tax (expense)/benefit

 

 

(11.1)

 

 

1.1 

 

 

(9.2)

 

 

(0.2)

 

 

(0.9)

 

 

(0.5)

 

 

(20.8)

Preferred dividends

 

 

(1.0)

 

 

 

 

(0.4)

 

 

 

 

 

 

 

 

(1.4)

Income/(loss) from
  continuing operations

 

 


31.9 

 

 


(3.4)

 

 


20.0 

 

 


0.7 

 

 


28.7 

 




(27.7)

 




50.2 

Income from
  discontinued operations

 

 


 

 


 

 


 

 


 

 


 

 


 

 


Net income/(loss)

 

$

31.9 

 

$

(3.4)

 

$

20.0 

 

$

0.7 

 

$

28.7 

 

$

(27.7)

 

$

50.2 


 

 

For the Nine Months Ended September 30, 2007

 

 

Regulated Companies

 

 

 

 

Distribution (1)

 

 

 

 

(Millions of Dollars)

 

Electric

 

Gas

 

Transmission

 

NU Enterprises

 

Other

 

Eliminations

 

Total

Operating revenues

 

$

3,784.7 

 

$

351.5 

 

$

214.7 

 

$

221.6 

 

$

287.1 

 

$

(312.2)

 

$

4,547.4 

Depreciation and amortization

 

 

(312.7)

 

 

(18.4)

 

 

(27.8)

 

 

(0.4)

 

 

(6.1)

 

 

3.0 

 

 

(362.4)

Restructuring and
  impairment charges

 

 


 

 


 

 


 

 


(0.2)

 

 


 

 


 

 


(0.2)

Other operating expenses

 

 

(3,230.6)

 

 

(303.9)

 

 

(84.4)

 

 

(206.9)

 

 

(269.3)

 

 

306.4 

 

 

(3,788.7)

Operating income/(loss)

 

 

241.4 

 

 

29.2 

 

 

102.5 

 

 

14.1 

 

 

11.7 

 

 

(2.8)

 

 

396.1 

Interest expense, net of AFUDC

 

 

(127.1)

 

 

(13.6)

 

 

(26.0)

 

 

(7.0)

 

 

(25.4)

 

 

18.6 

 

 

(180.5)

Interest income

 

 

3.1 

 

 

0.1 

 

 

1.4 

 

 

1.8 

 

 

27.3 

 

 

(18.4)

 

 

15.3 

Other income/(loss), net

 

 

10.9 

 

 

1.0 

 

 

7.7 

 

 

 

 

113.1 

 

 

(111.4)

 

 

21.3 

Income tax expense

 

 

(35.7)

 

 

(6.2)

 

 

(27.4)

 

 

(2.0)

 

 

(2.6)

 

 

(1.5)

 

 

(75.4)

Preferred dividends

 

 

(3.0)

 

 

 

 

(1.2)

 

 

 

 

 

 

 

 

(4.2)

Income/(loss) from
  continuing operations

 

 


89.6 

 

 


10.5 

 

 


57.0 

 

 


6.9 

 

 


124.1 

 




(115.5)

 




172.6 

Income from
  discontinued operations

 

 


 

 


 

 


 

 


1.2 

 

 


 

 


 

 


1.2 

Net income/(loss)

 

$

89.6 

 

$

10.5 

 

$

57.0 

 

$

8.1 

 

$

124.1 

 

$

(115.5)

 

$

173.8 

Total assets (2)

 

$

9,618.7 

 

$

1,266.2 

 

$

 

$

165.9 

 

$

4.394.5 

 

$

(4,106.3)

 

$

11,339.0 

Cash flows for total
  investments in plant

 

$


259.5 

 

$


43.3 

 

$


436.5 

 

$


6.8 

 

$


4.1 

 


$


 


$


750.2 


(1)

Includes PSNH's generation activities.  


(2)

Information for segmenting total assets between electric distribution and transmission is not available at September 30, 2007.  For NU and subsidiaries, distribution and transmission assets are disclosed in the electric distribution column above.  



30



 

 

For the Three Months Ended September 30, 2006

 

 

Regulated Companies

 

 

 

 

Distribution (1)

 

 

 

 

(Millions of Dollars)

 

Electric

 

Gas

 

Transmission

 

NU Enterprises

 

Other

 

Eliminations

 

Total

Operating revenues

 

$

1,396.0 

 

$

62.6 

 

$

58.0 

 

$

80.4 

 

$

91.8 

 

$

(96.0)

 

$

1,592.8 

Depreciation and amortization

 

 

(87.1)

 

 

(5.7)

 

 

(7.6)

 

 

(0.2)

 

 

(4.8)

 

 

3.5 

 

 

(101.9)

Restructuring and
  impairment charges

 

 


 

 


 

 


 

 


(1.3)

 

 


 

 


 

 


(1.3)

Other operating expenses

 

 

(1,241.8)

 

 

(61.7)

 

 

(24.1)

 

 

(93.7)

 

 

(84.1)

 

 

92.2 

 

 

(1,413.2)

Operating income/(loss)

 

 

67.1 

 

 

(4.8)

 

 

26.3 

 

 

(14.8)

 

 

2.9 

 

 

(0.3)

 

 

76.4 

Interest expense, net of AFUDC

 

 

(38.7)

 

 

(4.2)

 

 

(6.5)

 

 

(5.3)

 

 

(9.7)

 

 

4.3 

 

 

(60.1)

Interest income

 

 

1.7 

 

 

 

 

0.1 

 

 

0.4 

 

 

5.6 

 

 

(6.1)

 

 

1.7 

Other income/(loss), net

 

 

6.5 

 

 

0.4 

 

 

2.0 

 

 

 

 

18.0 

 

 

(16.5)

 

 

10.4 

Income tax benefit /(expense)

 

 

57.5 

 

 

3.3 

 

 

(3.4)

 

 

14.1 

 

 

4.8 

 

 

(0.6)

 

 

75.7 

Preferred dividends

 

 

(1.1)

 

 

 

 

(0.3)

 

 

 

 

 

 

 

 

(1.4)

Income/(loss) from
  continuing operations

 

 


93.0 

 

 


(5.3)

 

 


18.2 

 

 


(5.6)

 

 


21.6 

 

 


(19.2)

 

 


102.7 

Income from
  discontinued operations

 

 


 

 


 

 


 

 


8.8 

 

 


 

 


 

 


8.8 

Net income/(loss)

 

$

93.0 

 

$

(5.3)

 

$

18.2 

 

$

3.2 

 

$

21.6 

 

$

(19.2)

 

$

111.5 


 

 

For the Nine Months Ended September 30, 2006

 

 

Regulated Companies

 

 

 

 

Distribution (1)

 

 

 

 

(Millions of Dollars)

 

Electric

 

Gas

 

Transmission

 

NU Enterprises

 

Other

 

Eliminations

 

Total

Operating revenues

 

$

4,081.2 

 

$

335.1 

 

$

155.2 

 

$

854.0 

 

$

263.5 

 

$

(287.8)

 

$

5,401.2 

Depreciation and amortization

 

 

(327.4)

 

 

(17.0)

 

 

(22.0)

 

 

(0.5)

 

 

(14.0)

 

 

10.5 

 

 

(370.4)

Restructuring and
  impairment charges

 

 


 

 


 

 


 

 


(9.7)

 

 


 

 


 

 


(9.7)

Other operating expenses

 

 

(3,533.8)

 

 

(297.5)

 

 

(67.3)

 

 

(996.0)

 

 

(245.8)

 

 

276.6 

 

 

(4,863.8)

Operating income/(loss)

 

 

220.0 

 

 

20.6 

 

 

65.9 

 

 

(152.2)

 

 

3.7 

 

 

(0.7)

 

 

157.3 

Interest expense, net of AFUDC

 

 

(119.7)

 

 

(12.7)

 

 

(16.0)

 

 

(22.7)

 

 

(28.4)

 

 

19.1 

 

 

(180.4)

Interest income

 

 

7.3 

 

 

 

 

0.2 

 

 

4.0 

 

 

20.1 

 

 

(21.8)

 

 

9.8 

Other income/(loss), net

 

 

16.6 

 

 

0.8 

 

 

4.9 

 

 

(0.1)

 

 

105.9 

 

 

(99.4)

 

 

28.7 

Income tax benefit/(expense)

 

 

23.1 

 

 

(2.3)

 

 

(10.5)

 

 

70.0 

 

 

6.5 

 

 

(1.7)

 

 

85.1 

Preferred dividends

 

 

(3.3)

 

 

 

 

(0.9)

 

 

 

 

 

 

 

 

(4.2)

Income/(loss) from
  continuing operations

 

 


144.0 

 

 


6.4 

 

 


43.6 

 

 


(101.0)

 

 


107.8 

 

 


(104.5)

 




96.3 

Income from
  discontinued operations

 

 

 

 


 

 


 

 


27.3 

 

 


 

 


 

 


27.3 

Net income/(loss)

 

$

144.0 

 

$

6.4 

 

$

43.6 

 

$

(73.7)

 

$

107.8 

 

$

(104.5)

 

$

123.6 

Cash flows for total
  investments in plant

 

$


217.9 

 

$


62.3 

 

$


285.2 

 

$


17.2 

 

$


17.7 

 


$


-

 


$


600.3 


(1)

Includes PSNH's generation activities.  




31


The regulated companies information related to the distribution and transmission segments for CL&P, PSNH and WMECO for the three and nine months ended September 30, 2007 and 2006 is as follows:


 

 

CL&P - For the Three Months Ended September 30, 2007

(Millions of Dollars)

 

Distribution

 

Transmission

 

Total

Operating revenues

 

$

862.5 

 

$

55.9 

 

918.4 

Depreciation and amortization

 

 

(73.0)

 

 

(7.4)

 

 

(80.4)

Other operating expenses

 

 

(745.0)

 

 

(21.6)

 

 

(766.6)

Operating income

 

 

44.5 

 

 

26.9 

 

 

71.4 

Interest expense, net of AFUDC

 

 

(28.0)

 

 

(7.6)

 

 

(35.6)

Interest income

 

 

0.8 

 

 

0.3 

 

 

1.1 

Other income, net

 

 

2.6 

 

 

3.9 

 

 

6.5 

Income tax expense

 

 

(2.2)

 

 

(6.2)

 

 

(8.4)

Preferred dividends

 

 

(1.0)

 

 

(0.4)

 

 

(1.4)

Net income

 

$

16.7 

 

$

16.9 

 

33.6 


 

 

CL&P - For the Nine Months Ended September 30, 2007

(Millions of Dollars)

 

Distribution

 

Transmission

 

Total

Operating revenues

 

$

2,668.0 

 

$

164.5 

 

2,832.5 

Depreciation and amortization

 

 

(211.6)

 

 

(21.5)

 

 

(233.1)

Other operating expenses

 

 

(2,324.2)

 

 

(60.9)

 

 

(2,385.1)

Operating income

 

 

132.2 

 

 

82.1 

 

 

214.3 

Interest expense, net of AFUDC

 

 

(82.0)

 

 

(21.6)

 

 

(103.6)

Interest income

 

 

2.2 

 

 

1.2 

 

 

3.4 

Other income, net

 

 

9.7 

 

 

7.3 

 

 

17.0 

Income tax expense

 

 

(14.8)

 

 

(20.5)

 

 

(35.3)

Preferred dividends

 

 

(3.0)

 

 

(1.2)

 

 

(4.2)

Net income

 

$

44.3 

 

$

47.3 

 

91.6 

Cash flows for total investments in plant

 

$

166.5 

 

$

383.6 

 

$

550.1 


 

 

CL&P - For the Three Months Ended September 30, 2006

(Millions of Dollars)

 

Distribution

 

Transmission

 

Total

Operating revenues

 

$

1,040.5 

 

$

42.8 

 

1,083.3 

Depreciation and amortization

 

 

(63.9)

 

 

(5.7)

 

 

(69.6)

Other operating expenses

 

 

(942.0)

 

 

(17.0)

 

 

(959.0)

Operating income

 

 

34.6 

 

 

20.1 

 

 

54.7 

Interest expense, net of AFUDC

 

 

(24.0)

 

 

(5.2)

 

 

(29.2)

Interest income

 

 

1.2 

 

 

0.1 

 

 

1.3 

Other income, net

 

 

5.2 

 

 

2.0 

 

 

7.2 

Income tax benefit/(expense)

 

 

68.5 

 

 

(1.5)

 

 

67.0 

Preferred dividends

 

 

(1.1)

 

 

(0.3)

 

 

(1.4)

Net income

 

$

84.4 

 

$

15.2 

 

99.6 


 

 

CL&P - For the Nine Months Ended September 30, 2006

(Millions of Dollars)

 

Distribution

 

Transmission

 

Total

Operating revenues

 

$

2,918.1 

 

$

109.7 

 

3,027.8 

Depreciation and amortization

 

 

(183.9)

 

 

(16.3)

 

 

(200.2)

Other operating expenses

 

 

(2,618.1)

 

 

(46.1)

 

 

(2,664.2)

Operating income

 

 

116.1 

 

 

47.3 

 

 

163.4 

Interest expense, net of AFUDC

 

 

(74.9)

 

 

(12.2)

 

 

(87.1)

Interest income

 

 

5.6 

 

 

0.2 

 

 

5.8 

Other income, net

 

 

13.3 

 

 

4.5 

 

 

17.8 

Income tax benefit/(expense)

 

 

57.4 

 

 

(4.9)

 

 

52.5 

Preferred dividends

 

 

(3.3)

 

 

(0.9)

 

 

(4.2)

Net income

 

$

114.2 

 

$

34.0 

 

148.2 

Cash flows for total investments in plant

 

$

129.6 

 

$

258.8 

 

$

388.4 




32



 

 

PSNH - For the Three Months Ended September 30, 2007

(Millions of Dollars)

 

Distribution (1)

 

Transmission

 

Total

Operating revenues

 

$

272.8 

 

$

11.5 

 

284.3 

Depreciation and amortization

 

 

(32.6)

 

 

(1.5)

 

 

(34.1)

Other operating expenses

 

 

(212.6)

 

 

(4.9)

 

 

(217.5)

Operating income

 

 

27.6 

 

 

5.1 

 

 

32.7 

Interest expense, net of AFUDC

 

 

(10.9)

 

 

(0.8)

 

 

(11.7)

Interest income

 

 

0.1 

 

 

 

 

0.1 

Other income, net

 

 

 

 

 

 

Income tax expense

 

 

(5.8)

 

 

(2.3)

 

 

(8.1)

Net income

 

$

11.0 

 

$

2.0 

 

13.0 


 

 

PSNH - For the Nine Months Ended September 30, 2007

(Millions of Dollars)

 

Distribution (1)

 

Transmission

 

Total

Operating revenues

 

$

778.2 

 

$

33.5 

 

811.7 

Depreciation and amortization

 

 

(70.3)

 

 

(4.4)

 

 

(74.7)

Other operating expenses

 

 

(633.4)

 

 

(15.3)

 

 

(648.7)

Operating income

 

 

74.5 

 

 

13.8 

 

 

88.3 

Interest expense, net of AFUDC

 

 

(31.9)

 

 

(2.9)

 

 

(34.8)

Interest income

 

 

0.4 

 

 

0.1 

 

 

0.5 

Other income, net

 

 

0.7 

 

 

0.4 

 

 

1.1 

Income tax expense

 

 

(12.0)

 

 

(4.9)

 

 

(16.9)

Net income

 

$

31.7 

 

$

6.5 

 

38.2 

Cash flows for total investments in plant

 

$

71.9 

 

$

41.2 

 

$

113.1 


 

 

PSNH - For the Three Months Ended September 30, 2006

(Millions of Dollars)

 

Distribution (1)

 

Transmission

 

Total

Operating revenues

 

$

255.3 

 

$

10.5 

 

265.8 

Depreciation and amortization

 

 

(18.2)

 

 

(1.3)

 

 

(19.5)

Other operating expenses

 

 

(213.5)

 

 

(4.7)

 

 

(218.2)

Operating income

 

 

23.6 

 

 

4.5 

 

 

28.1 

Interest expense, net of AFUDC

 

 

(10.5)

 

 

(0.9)

 

 

(11.4)

Interest income

 

 

0.2 

 

 

 

 

0.2 

Other income, net

 

 

1.0 

 

 

 

 

1.0 

Income tax expense

 

 

(8.5)

 

 

(1.5)

 

 

(10.0)

Net income

 

$

5.8 

 

$

2.1 

 

7.9 


 

 

PSNH - For the Nine Months Ended September 30, 2006

(Millions of Dollars)

 

Distribution (1)

 

Transmission

 

Total

Operating revenues

 

$

844.6 

 

$

31.1 

 

875.7 

Depreciation and amortization

 

 

(130.5)

 

 

(3.9)

 

 

(134.4)

Other operating expenses

 

 

(637.7)

 

 

(14.3)

 

 

(652.0)

Operating income

 

 

76.4 

 

 

12.9 

 

 

89.3 

Interest expense, net of AFUDC

 

 

(31.9)

 

 

(2.5)

 

 

(34.4)

Interest income

 

 

0.8 

 

 

 

 

0.8 

Other income, net

 

 

2.8 

 

 

0.4 

 

 

3.2 

Income tax expense

 

 

(26.9)

 

 

(4.1)

 

 

(31.0)

Net income

 

$

21.2 

 

$

6.7 

 

27.9 

Cash flows for total investments in plant

 

$

65.0 

 

$

16.9 

 

$

81.9 


(1)

Includes PSNH's generation activities.  



33



 

 

WMECO - For the Three Months Ended September 30, 2007

(Millions of Dollars)

 

Distribution

 

Transmission

 

Total

Operating revenues

 

$

108.1 

 

$

5.4 

 

113.5 

Depreciation and amortization

 

 

(11.0)

 

 

(0.6)

 

 

(11.6)

Other operating expenses

 

 

(85.8)

 

 

(2.5)

 

 

(88.3)

Operating income

 

 

11.3 

 

 

2.3 

 

 

13.6 

Interest expense, net of AFUDC

 

 

(4.3)

 

 

(0.5)

 

 

(4.8)

Interest income

 

 

0.2 

 

 

 

 

0.2 

Other income, net

 

 

 

 

 

 

Income tax expense

 

 

(3.0)

 

 

(0.7)

 

 

(3.7)

Net income

 

$

4.2 

 

$

1.1 

 

5.3 


 

 

WMECO - For the Nine Months Ended September 30, 2007

(Millions of Dollars)

 

Distribution

 

Transmission

 

Total

Operating revenues

 

$

338.7 

 

$

16.7 

 

355.4 

Depreciation and amortization

 

 

(30.8)

 

 

(1.9)

 

 

(32.7)

Other operating expenses

 

 

(273.2)

 

 

(8.2)

 

 

(281.4)

Operating income

 

 

34.7 

 

 

6.6 

 

 

41.3 

Interest expense, net of AFUDC

 

 

(13.2)

 

 

(1.5)

 

 

(14.7)

Interest income

 

 

0.5 

 

 

0.1 

 

 

0.6 

Other income, net

 

 

0.6 

 

 

0.1 

 

 

0.7 

Income tax expense

 

 

(9.0)

 

 

(2.1)

 

 

(11.1)

Net income

 

$

13.6 

 

$

3.2 

 

$

16.8 

Cash flows for total investments in plant

 

$

21.1 

 

$

11.7 

 

32.8 


 

 

WMECO - For the Three Months Ended September 30, 2006

(Millions of Dollars)

 

Distribution

 

Transmission

 

Total

Operating revenues

 

$

100.3 

 

$

4.7 

 

105.0 

Depreciation and amortization

 

 

(5.0)

 

 

(0.6)

 

 

(5.6)

Other operating expenses

 

 

(86.4)

 

 

(2.4)

 

 

(88.8)

Operating income

 

 

8.9 

 

 

1.7 

 

 

10.6 

Interest expense, net of AFUDC

 

 

(4.2)

 

 

(0.4)

 

 

(4.6)

Interest income

 

 

0.3 

 

 

 

 

0.3 

Other income, net

 

 

0.3 

 

 

 

 

0.3 

Income tax expense

 

 

(2.5)

 

 

(0.4)

 

 

(2.9)

Net income

 

$

2.8 

 

$

0.9 

 

$

3.7 


 

 

WMECO - For the Nine Months Ended September 30, 2006

(Millions of Dollars)

 

Distribution

 

Transmission

 

Total

Operating revenues

 

$

318.7 

 

$

14.3 

 

333.0 

Depreciation and amortization

 

 

(12.9)

 

 

(1.7)

 

 

(14.6)

Other operating expenses

 

 

(278.3)

 

 

(6.9)

 

 

(285.2)

Operating income

 

 

27.5 

 

 

5.7 

 

 

33.2 

Interest expense, net of AFUDC

 

 

(12.8)

 

 

(1.3)

 

 

(14.1)

Interest income

 

 

0.6 

 

 

-  

 

 

0.6 

Other income, net

 

 

0.7 

 

 

 

 

0.7 

Income tax expense

 

 

(7.4)

 

 

(1.5)

 

 

(8.9)

Net income

 

$

8.6 

 

$

2.9 

 

$

11.5 

Cash flows for total investments in plant

 

$

23.2 

 

$

9.1 

 

$

32.3 


11.

SUBSEQUENT EVENT (PSNH)


On an annual basis, PSNH files with the New Hampshire Public Utilities Commission (NHPUC) a stranded cost recovery charge/energy service (SCRC/ES) reconciliation filing for the preceding calendar year.  The NHPUC reviews the filing, including a prudence review of the operations within PSNH's generation segment.  On May 1, 2007, PSNH filed its 2006 SCRC/ES reconciliation with the NHPUC.  




34


On November 5, 2007, PSNH, the New Hampshire Office of Consumer Advocate, and staff of the NHPUC entered into a settlement agreement resolving all outstanding issues in this proceeding with de minimis adjustments to PSNH's SCRC/ES reconciliation.  The settlement agreement also favorably resolved the NHPUC staff's audit of PSNH's Northern Wood Power Project costs, with no disallowances.  The settlement agreement was the subject of a NHPUC hearing on November 6, 2007, and a decision is expected by the end of 2007.  If the settlement agreement is approved by the NHPUC, this matter will not have a material adverse impact on PSNH's net income, financial position or cash flows.



35


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Trustees and Shareholders of Northeast Utilities:


We have reviewed the accompanying condensed consolidated balance sheet of Northeast Utilities and subsidiaries (the "Company") as of September 30, 2007, and the related condensed consolidated statements of income for the three-month and nine-month periods ended September 30, 2007 and 2006, and of cash flows for the nine-month periods ended September 30, 2007 and 2006.  These interim financial statements are the responsibility of the Company's management.


We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States).  A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters.  It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole.  Accordingly, we do not express such an opinion.


Based on our reviews, we are not aware of any material modifications that should be made to such condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.


As discussed in Note 1.E., the Company adopted Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement No. 109, as of January 1, 2007.


We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and consolidated statement of capitalization of Northeast Utilities and subsidiaries as of December 31, 2006, and the related consolidated statements of income, comprehensive income, shareholders' equity, and cash flows for the year then ended (not presented herein); and in our report dated February 26, 2007 (which report included an explanatory paragraph related to recording charges, gains and losses in connection with the Company's ongoing divestiture activities, realizing a reduction to income tax expense related to a ruling that certain income taxes could not be used to reduce customer's rates, and the adoption of Statement of Financial Accounting Standard No. 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans), we expressed an unqualified opinion on those consolidated financial statements.  In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2006 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.


/s/

Deloitte & Touche LLP

 

Deloitte & Touche LLP


Hartford, Connecticut

November 8, 2007



36


THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES



37



THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

 

 

 

 

 

 

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

 

 

 

(Unaudited)

 

 

 

 

 

 

 

September 30,

 

 

December 31,

 

 

2007

 

 

2006

 

 

(Thousands of Dollars)

ASSETS

 

 

 

 

 

 

 

 

 

 

 

Current Assets:

 

 

 

 

 

  Cash

 

$                      10,669 

 

 

$                        3,310 

  Investments in securitizable assets

 

339,309 

 

 

375,656 

  Receivables, less provision for uncollectible

 

 

 

 

 

    accounts of $2,188 in 2007 and $1,679 in 2006

 

91,770 

 

 

73,052 

  Accounts receivable from affiliated companies

 

738 

 

 

1,965 

  Unbilled revenues

 

7,158 

 

 

8,044 

  Materials and supplies

 

54,456 

 

 

39,447 

  Derivative assets - current

 

47,085 

 

 

45,031 

  Prepayments and other

 

30,575 

 

 

15,945 

 

 

581,760 

 

 

562,450 

 

 

 

 

 

 

Property, Plant and Equipment:

 

 

 

 

 

  Electric utility

 

4,661,852 

 

 

4,557,231 

     Less: Accumulated depreciation

 

1,274,399 

 

 

1,260,526 

 

 

3,387,453 

 

 

3,296,705 

  Construction work in progress

 

745,541 

 

 

337,665 

 

 

4,132,994 

 

 

3,634,370 

 

 

 

 

 

 

Deferred Debits and Other Assets:

 

 

 

 

 

  Regulatory assets

 

1,279,243 

 

 

1,477,375 

  Prepaid pension

 

303,854 

 

 

243,139 

  Derivative assets - long-term

 

259,112 

 

 

249,423 

  Other

 

143,343 

 

 

154,537 

 

 

1,985,552 

 

 

2,124,474 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Assets

 

$                 6,700,306 

 

 

$                 6,321,294 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 




38



THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

 

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

 

 

 

 

 

 

September 30,

 

 

December 31,

 

 

2007

 

 

2006

 

 

(Thousands of Dollars)

LIABILITIES AND CAPITALIZATION

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities:

 

 

 

 

 

  Notes payable to affiliated companies

 

$                    130,525 

 

 

$                    258,925 

  Accounts payable

 

323,448 

 

 

326,163 

  Accounts payable to affiliated companies

 

36,818 

 

 

47,906 

  Accrued taxes

 

35,221 

 

 

186,647 

  Accrued interest

 

39,285 

 

 

29,587 

  Derivative liabilities - current

 

6,371 

 

 

4,101 

  Other

 

79,168 

 

 

80,543 

 

 

650,836 

 

 

933,872 

 

 

 

 

 

 

Rate Reduction Bonds

 

629,488 

 

 

743,899 

 

 

 

 

 

 

Deferred Credits and Other Liabilities:

 

 

 

 

 

  Accumulated deferred income taxes

 

667,604 

 

 

719,470 

  Accumulated deferred investment tax credits

 

22,064 

 

 

24,019 

  Deferred contractual obligations

 

163,280 

 

 

185,195 

  Regulatory liabilities

 

627,544 

 

 

582,841 

  Derivative liabilities - long-term

 

27,852 

 

 

31,923 

  Accrued postretirement benefits

 

72,534 

 

 

85,768 

  Other

 

170,107 

 

 

127,638 

 

 

1,750,985 

 

 

1,756,854 

Capitalization:

 

 

 

 

 

  Long-Term Debt

 

2,025,924 

 

 

1,519,440 

 

 

 

 

 

 

  Preferred Stock - Non-Redeemable

 

116,200 

 

 

116,200 

 

 

 

 

 

 

  Common Stockholder's Equity:

 

 

 

 

 

    Common stock, $10 par value - authorized

 

 

 

 

 

      24,500,000 shares; 6,035,205 shares outstanding

 

 

 

 

 

      in 2007 and 2006

 

60,352 

 

 

60,352 

    Capital surplus, paid in

 

938,198 

 

 

672,693 

    Retained earnings

 

529,908 

 

 

513,344 

    Accumulated other comprehensive (loss)/income

 

(1,585)

 

 

4,640 

  Common Stockholder's Equity

 

1,526,873 

 

 

1,251,029 

Total Capitalization

 

3,668,997 

 

 

2,886,669 

 

 

 

 

 

 

Commitments and Contingencies (Note 6)

 

 

 

 

 

.

 

 

 

 

 

Total Liabilities and Capitalization

 

$                 6,700,306 

 

 

$                 6,321,294 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 




39



THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

 

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

 

 

Three Months Ended

 

 

Nine Months Ended

 

 

September 30,

 

 

September 30,

 

 

2007

 

 

2006

 

 

2007

 

 

2006

 

(Thousands of Dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

 

$       918,418 

 

 

$    1,083,299 

 

 

$    2,832,483 

 

 

$    3,027,779 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Expenses:

 

 

 

 

 

 

 

 

 

 

 

  Operation -

 

 

 

 

 

 

 

 

 

 

 

     Fuel, purchased and net interchange power

 

604,953 

 

 

726,271 

 

 

1,809,996 

 

 

1,992,936 

     Other

 

87,946 

 

 

158,601 

 

 

365,184 

 

 

472,979 

  Maintenance

 

29,391 

 

 

31,246 

 

 

80,281 

 

 

74,803 

  Depreciation

 

38,354 

 

 

37,802 

 

 

114,818 

 

 

110,235 

  Amortization of regulatory assets/(liabilities), net

 

6,156 

 

 

(1,811)

 

 

15,493 

 

 

(6,132)

  Amortization of rate reduction bonds

 

35,904 

 

 

33,614 

 

 

102,833 

 

 

96,137 

  Taxes other than income taxes

 

44,291 

 

 

42,847 

 

 

129,540 

 

 

123,385 

    Total operating expenses

 

846,995 

 

 

1,028,570 

 

 

2,618,145 

 

 

2,864,343 

Operating Income

 

71,423 

 

 

54,729 

 

 

214,338 

 

 

163,436 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Expense:

 

 

 

 

 

 

 

 

 

 

 

  Interest on long-term debt

 

21,457 

 

 

17,977 

 

 

60,637 

 

 

46,924 

  Interest on rate reduction bonds

 

9,230 

 

 

11,459 

 

 

29,097 

 

 

36,025 

  Other interest

 

4,897 

 

 

 (254)

 

 

13,849 

 

 

4,170 

    Interest expense, net

 

35,584 

 

 

29,182 

 

 

103,583 

 

 

87,119 

Other Income, Net

 

7,545 

 

 

8,504 

 

 

20,275 

 

 

23,500 

Income Before Income Tax Expense/(Benefit)

 

43,384 

 

 

34,051 

 

 

131,030 

 

 

99,817 

Income Tax Expense/(Benefit)

 

8,408 

 

 

(66,982)

 

 

35,274 

 

 

(52,518)

Net Income

 

$         34,976 

 

   

$       101,033 

 

   

$         95,756 

 

 

$        152,335 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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




40



THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

 

 

 

 

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

 

 

 

Nine Months Ended

 

September 30,

 

2007

 

2006

 

 (Thousands of Dollars)

Operating Activities:

 

 

 

  Net income

$                    95,756 

 

$                  152,335 

  Adjustments to reconcile to net cash flows

 

 

 

   provided by operating activities:

 

 

 

    Bad debt expense

13,720 

 

12,651 

    Depreciation

114,818 

 

110,235 

    Deferred income taxes

 (27,738)

 

10,391 

    Amortization of regulatory assets/(liabilities), net

15,493 

 

 (6,132)

    Amortization of rate reduction bonds

102,833 

 

96,137 

    Amortization/(deferral) of recoverable energy costs

3,096 

 

 (3,937)

    Pension income, net of capitalized portion

 (6,570)

 

 (2,480)

    Regulatory overrecoveries/(refunds)

66,976 

 

 (117,670)

    Deferred contractual obligations

 (21,915)

 

 (48,657)

    Other non-cash adjustments

(13,382)

 

 (13,729)

    Other sources of cash

 

14,171 

    Other uses of cash

 (24,703)

 

 (4,462)

  Changes in current assets and liabilities:

 

 

 

    Receivables and unbilled revenues, net

 (13,984)

 

8,603 

    Materials and supplies

 (15,009)

 

 (5,842)

    Investments in securitizable assets

18,138 

 

 (20,284)

    Other current assets

 (15,798)

 

 (13,179)

    Accounts payable

 (34,858)

 

26,853 

    Taxes receivable and accrued taxes

 (162,843)

 

 (57,612)

    Other current liabilities

7,755 

 

11,464 

Net cash flows provided by operating activities

101,785 

 

148,856 

 

 

 

 

Investing Activities:

 

 

 

  Investments in plant

 (550,128)

 

 (388,365)

  Proceeds from sales of investment securities

1,515 

 

1,524 

  Purchases of investment securities

 (1,565)

 

 (1,566)

  Rate reduction bond escrow

2,257 

 

 (52,020)

  Other investing activities

2,164 

 

 (1,620)

Net cash flows used in investing activities

 (545,757)

 

 (442,047)

 

 

 

 

Financing Activities:

 

 

 

  Issuance of long-term debt

500,000 

 

250,000 

  Retirement of rate reduction bonds

 (114,411)

 

 (73,217)

  Decrease in NU Money Pool borrowing

 (128,400)

 

 (15,700)

  Capital contributions from Northeast Utilities Parent

265,000 

 

60,000 

  Increase in short-term debt

         - 

 

130,000 

  Cash dividends on preferred stock

 (4,169)

 

 (4,169)

  Cash dividends on common stock

 (59,386)

 

 (47,798)

  Other financing activities

 (7,303)

 

 (1,492)

Net cash flows provided by financing activities

451,331 

 

297,624 

Net increase in cash

7,359 

 

4,433 

Cash - beginning of period

3,310 

 

2,301 

Cash - end of period

$                    10,669 

 

$                      6,734 

 

 

 

 

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




41


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42


PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE



43



PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

 

 

 

 

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

 

(Unaudited)

 

 

 

 

September 30,

 

December 31,

 

2007

 

2006

 

(Thousands of Dollars)

ASSETS

 

 

 

 

 

 

 

Current Assets:

 

 

 

  Cash

$                        3,308 

 

$                             31 

  Special deposits

4,000 

 

  Receivables, less provision for uncollectible

 

 

 

    accounts of $2,438 in 2007 and $2,626 in 2006

94,443 

 

86,784 

  Accounts receivable from affiliated companies

82 

 

590 

  Unbilled revenues

39,078 

 

44,433 

  Notes receivable from affiliated companies

7,300 

 

  Taxes receivable

500 

 

6,671 

  Fuel, materials and supplies

81,595 

 

84,856 

  Derivative assets - current

574 

 

  Prepayments and other

6,794 

 

12,652 

 

237,674 

 

236,017 

 

 

 

 

Property, Plant and Equipment:

 

 

 

  Electric utility

1,960,131 

 

1,893,124 

  Other

6,288 

 

5,816 

 

1,966,419 

 

1,898,940 

     Less: Accumulated depreciation

729,823 

 

723,764 

 

1,236,596 

 

1,175,176 

  Construction work in progress

92,745 

 

67,202 

 

1,329,341 

 

1,242,378 

 

 

 

 

Deferred Debits and Other Assets:

 

 

 

  Regulatory assets

448,768 

 

524,536 

  Other

73,226 

 

68,345 

 

521,994 

 

592,881 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Assets

$                 2,089,009