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

FORM 10-Q


T

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

 

 

 

For the Quarterly Period Ended September 30, 2014     

 

OR     

£

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

 

 

 

For the transition period from ____________ to ____________



Commission
File Number

Registrant; State of Incorporation;
Address; and Telephone Number

I.R.S. Employer
Identification No.

 

 

 

1-5324

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

04-2147929


0-00404

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

06-0303850


1-02301

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

04-1278810


1-6392

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

02-0181050


0-7624

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

04-1961130




 






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


 

Yes

No

 

 

 

 

T

£


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


 

Yes

No

 

 

 

 

T

£


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


 

Large
Accelerated Filer

 

Accelerated
Filer

 

Non-accelerated
Filer

 

 

 

 

 

 

Northeast Utilities

T

 

£

 

£

The Connecticut Light and Power Company

£

 

£

 

T

NSTAR Electric Company

£

 

£

 

T

Public Service Company of New Hampshire

£

 

£

 

T

Western Massachusetts Electric Company

£

 

£

 

T


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


 

Yes

No

 

 

 

Northeast Utilities

£

T

The Connecticut Light and Power Company

£

T

NSTAR Electric Company

£

T

Public Service Company of New Hampshire

£

T

Western Massachusetts Electric Company

£

T


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


Company - Class of Stock

Outstanding as of October 31, 2014

Northeast Utilities
Common shares, $5.00 par value

316,799,371 shares

 

 

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

6,035,205 shares

 

 

NSTAR Electric Company
Common stock, $1.00 par value

100 shares

 

 

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

301 shares

 

 

Western Massachusetts Electric Company
Common stock, $25.00 par value

434,653 shares


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


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






GLOSSARY OF TERMS


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

 

CURRENT OR FORMER NU COMPANIES, SEGMENTS OR INVESTMENTS:

 

 

CL&P

The Connecticut Light and Power Company

CYAPC

Connecticut Yankee Atomic Power Company

Hopkinton

Hopkinton LNG Corp., a wholly owned subsidiary of Yankee Energy System, Inc.

HWP

HWP Company, formerly the Holyoke Water Power Company

MYAPC

Maine Yankee Atomic Power Company

NGS

Northeast Generation Services Company

NPT

Northern Pass Transmission LLC

NSTAR

Parent Company of NSTAR Electric, NSTAR Gas and other subsidiaries (prior to the merger with NU)

NSTAR Electric

NSTAR Electric Company

NSTAR Electric & Gas

NSTAR Electric & Gas Corporation, a former Northeast Utilities service company (effective January 1, 2014 merged into NUSCO)

NSTAR Gas

NSTAR Gas Company

NU Enterprises

NU Enterprises, Inc., the parent company of NGS, Select Energy, Select Energy Contracting, Inc., E.S. Boulos Company and NSTAR Communications, Inc.

NU or the Company

Northeast Utilities and subsidiaries

NU parent and other companies

NU parent and other companies is comprised of NU parent, NUSCO and other subsidiaries, which primarily include NU Enterprises, HWP, RRR (a real estate subsidiary), the non-energy-related subsidiaries of Yankee (Yankee Energy Services Company and Yankee Energy Financial Services Company), and the consolidated operations of CYAPC and YAEC

NUSCO

Northeast Utilities Service Company (effective January 1, 2014 includes the operations of NSTAR Electric & Gas)

NUTV

NU Transmission Ventures, Inc., the parent company of NPT and Renewable Properties, Inc.

PSNH

Public Service Company of New Hampshire

Regulated companies

NU's Regulated companies, comprised of the electric distribution and transmission businesses of CL&P, NSTAR Electric, PSNH, and WMECO, the natural gas distribution businesses of Yankee Gas and NSTAR Gas, the generation activities of PSNH and WMECO, and NPT

RRR

The Rocky River Realty Company

Select Energy

Select Energy, Inc.

WMECO

Western Massachusetts Electric Company

YAEC

Yankee Atomic Electric Company

Yankee

Yankee Energy System, Inc.

Yankee Companies

CYAPC, YAEC and MYAPC

Yankee Gas

Yankee Gas Services Company

REGULATORS:

 

DEEP

Connecticut Department of Energy and Environmental Protection

DOE

U.S. Department of Energy

DOER

Massachusetts Department of Energy Resources

DPU

Massachusetts Department of Public Utilities

EPA

U.S. Environmental Protection Agency

FERC

Federal Energy Regulatory Commission

ISO-NE

ISO New England, Inc., the New England Independent System Operator

MA DEP

Massachusetts Department of Environmental Protection

NHPUC

New Hampshire Public Utilities Commission

PURA

Connecticut Public Utilities Regulatory Authority

SEC

U.S. Securities and Exchange Commission

SJC

Supreme Judicial Court of Massachusetts

OTHER:

 

AFUDC

Allowance For Funds Used During Construction

AOCI

Accumulated Other Comprehensive Income/(Loss)

ARO

Asset Retirement Obligation

C&LM

Conservation and Load Management

CfD

Contract for Differences

Clean Air Project

The construction of a wet flue gas desulphurization system, known as "scrubber technology," to reduce mercury emissions of the Merrimack coal-fired generation station in Bow, New Hampshire

CO2

Carbon dioxide

CPSL

Capital Projects Scheduling List

CTA

Competitive Transition Assessment

CWIP

Construction work in progress

EPS

Earnings Per Share

ERISA

Employee Retirement Income Security Act of 1974

ES

Default Energy Service



i






ESOP

Employee Stock Ownership Plan

ESPP

Employee Share Purchase Plan

FERC ALJ

FERC Administrative Law Judge

Fitch

Fitch Ratings

FMCC

Federally Mandated Congestion Charge

FTR

Financial Transmission Rights

GAAP

Accounting principles generally accepted in the United States of America

GSC

Generation Service Charge

GSRP

Greater Springfield Reliability Project

GWh

Gigawatt-Hours

HG&E

Holyoke Gas and Electric, a municipal department of the City of Holyoke, MA

HQ

Hydro-Québec, a corporation wholly owned by the Québec government, including its divisions that produce, transmit and distribute electricity in Québec, Canada

HVDC

High voltage direct current

Hydro Renewable Energy

Hydro Renewable Energy, Inc., a wholly owned subsidiary of Hydro-Québec

IPP

Independent Power Producers

ISO-NE Tariff

ISO-NE FERC Transmission, Markets and Services Tariff

kV

Kilovolt

kW

Kilowatt (equal to one thousand watts)

kWh

Kilowatt-Hours (the basic unit of electricity energy equal to one kilowatt of power supplied for one hour)

LNG

Liquefied natural gas

LRS

Supplier of last resort service

MGP

Manufactured Gas Plant

Millstone

Millstone Nuclear Generating station, made up of Millstone 1, Millstone 2, and Millstone 3. All three units were sold in March 2001.

MMBtu

One million British thermal units

Moody's

Moody's Investors Services, Inc.

MW

Megawatt

MWh

Megawatt-Hours

NEEWS

New England East-West Solution

Northern Pass

The high voltage direct current transmission line project from Canada into New Hampshire

NOx

Nitrogen oxides

NU 2013 Form 10-K

The Northeast Utilities and Subsidiaries 2013 combined Annual Report on Form 10-K as filed with the SEC

PAM

Pension and PBOP Rate Adjustment Mechanism

PBOP

Postretirement Benefits Other Than Pension

PBOP Plan

Postretirement Benefits Other Than Pension Plan that provides certain retiree health care benefits, primarily medical and dental, and life insurance benefits

PCRBs

Pollution Control Revenue Bonds

Pension Plan

Single uniform noncontributory defined benefit retirement plan

PPA

Pension Protection Act

RECs

Renewable Energy Certificates

Regulatory ROE

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

ROE

Return on Equity

RRB

Rate Reduction Bond or Rate Reduction Certificate

RSUs

Restricted share units

S&P

Standard & Poor's Financial Services LLC

SBC

Systems Benefits Charge

SCRC

Stranded Cost Recovery Charge

SERP

Supplemental Executive Retirement Plans and non-qualified defined benefit retirement plans

Settlement Agreements

The comprehensive settlement agreements reached by NU and NSTAR with the Massachusetts Attorney General and the DOER on February 15, 2012 related to the merger of NU and NSTAR (Massachusetts settlement agreements) and the comprehensive settlement agreement reached by NU and NSTAR with both the Connecticut Attorney General and the Connecticut Office of Consumer Counsel on March 13, 2012 related to the merger of NU and NSTAR (Connecticut settlement agreement).

SIP

Simplified Incentive Plan

SO2

Sulfur dioxide

SS

Standard service

TCAM

Transmission Cost Adjustment Mechanism

TSA

Transmission Service Agreement

UI

The United Illuminating Company



ii



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

TABLE OF CONTENTS

 

Page

PART I - FINANCIAL INFORMATION

 

 

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

 


Northeast Utilities and Subsidiaries (Unaudited)

 

Condensed Consolidated Balance Sheets

1

Condensed Consolidated Statements of Income

3

Condensed Consolidated Statements of Comprehensive Income

3

Condensed Consolidated Statements of Cash Flows

4

 

The Connecticut Light and Power Company (Unaudited)

 

Condensed Balance Sheets

5

Condensed Statements of Income

7

Condensed Statements of Comprehensive Income

7

Condensed Statements of Cash Flows

8

 

NSTAR Electric Company and Subsidiary (Unaudited)

 

Condensed Consolidated Balance Sheets

9

Condensed Consolidated Statements of Income

11

Condensed Consolidated Statements of Cash Flows

12

 

 

Public Service Company of New Hampshire and Subsidiary (Unaudited)

 

Condensed Consolidated Balance Sheets

13

Condensed Consolidated Statements of Income

15

Condensed Consolidated Statements of Comprehensive Income

15

Condensed Consolidated Statements of Cash Flows

16

 

Western Massachusetts Electric Company (Unaudited)

 

Condensed Balance Sheets

17

Condensed Statements of Income

19

Condensed Statements of Comprehensive Income

19

Condensed Statements of Cash Flows

20

 

 

Combined Notes to Condensed Consolidated Financial Statements (Unaudited)

21


ITEM 2 – Management's Discussion and Analysis of Financial Condition and Results of Operations for the Following Companies:


Northeast Utilities and Subsidiaries


40

The Connecticut Light and Power Company

54

NSTAR Electric Company and Subsidiary

57

Public Service Company of New Hampshire and Subsidiary

59

Western Massachusetts Electric Company

61

 

 

ITEM 3 – Quantitative and Qualitative Disclosures About Market Risk

63

 

 

ITEM 4 – Controls and Procedures

63

 

 

PART II – OTHER INFORMATION

 

 

 

ITEM 1 – Legal Proceedings

64

 

 

ITEM 1A – Risk Factors

64

 

 

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

64

 

 

ITEM 6 – Exhibits

65

 

 

SIGNATURES

67



iii






NORTHEAST UTILITIES AND SUBSIDIARIES

 

 

 

 

 

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

 

 

 

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30,

 

December 31,

(Thousands of Dollars)

2014 

 

2013 

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

 

Current Assets:

 

 

 

 

 

 

Cash and Cash Equivalents

$

 41,706 

 

$

 43,364 

 

Receivables, Net

 

 848,510 

 

 

 765,391 

 

Unbilled Revenues

 

 181,284 

 

 

 224,982 

 

Fuel, Materials and Supplies

 

 333,869 

 

 

 303,233 

 

Regulatory Assets

 

 445,962 

 

 

 535,791 

 

Marketable Securities

 

 114,722 

 

 

 92,427 

 

Prepayments and Other Current Assets

 

 135,497 

 

 

 121,861 

Total Current Assets

 

 2,101,550 

 

 

 2,087,049 

 

 

 

 

 

 

 

Property, Plant and Equipment, Net

 

 18,254,610 

 

 

 17,576,186 

 

 

 

 

 

 

 

Deferred Debits and Other Assets:

 

 

 

 

 

 

Regulatory Assets

 

 3,241,122 

 

 

 3,758,694 

 

Goodwill

 

 3,519,401 

 

 

 3,519,401 

 

Marketable Securities

 

 518,032 

 

 

 488,515 

 

Other Long-Term Assets

 

 347,596 

 

 

 365,692 

Total Deferred Debits and Other Assets

 

 7,626,151 

 

 

 8,132,302 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Assets

$

 27,982,311 

 

$

 27,795,537 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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



1




NORTHEAST UTILITIES AND SUBSIDIARIES

 

 

 

 

 

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

 

 

 

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30,

 

December 31,

(Thousands of Dollars)

2014 

 

2013 

 

 

 

 

 

 

 

 

LIABILITIES AND CAPITALIZATION

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities:

 

 

 

 

 

 

Notes Payable

$

 1,046,961 

 

$

 1,093,000 

 

Long-Term Debt - Current Portion

 

 245,583 

 

 

 533,346 

 

Accounts Payable

 

 608,639 

 

 

 742,251 

 

Regulatory Liabilities

 

 398,985 

 

 

 204,278 

 

Other Current Liabilities

 

 629,508 

 

 

 702,776 

Total Current Liabilities

 

 2,929,676 

 

 

 3,275,651 

 

 

 

 

 

 

 

 

Deferred Credits and Other Liabilities:

 

 

 

 

 

  

Accumulated Deferred Income Taxes

 

 4,257,996 

 

 

 4,029,026 

 

Regulatory Liabilities

 

 509,889 

 

 

 502,984 

 

Derivative Liabilities

 

 420,931 

 

 

 624,050 

 

Accrued Pension, SERP and PBOP

 

 787,550 

 

 

 896,844 

 

Other Long-Term Liabilities

 

 863,164 

 

 

 923,053 

Total Deferred Credits and Other Liabilities

 

 6,839,530 

 

 

 6,975,957 

 

 

 

 

 

 

 

 

Capitalization:

 

 

 

 

 

 

Long-Term Debt

 

 8,166,985 

 

 

 7,776,833 

 

 

 

 

 

 

 

 

 

Noncontrolling Interest - Preferred Stock of Subsidiaries

 

 155,568 

 

 

 155,568 

 

 

 

 

 

 

 

 

 

Equity:

 

 

 

 

 

 

  Common Shareholders' Equity:

 

 

 

 

 

 

 

Common Shares

 

 1,666,767 

 

 

 1,665,351 

 

  

Capital Surplus, Paid In

 

 6,219,516 

 

 

 6,192,765 

 

 

Retained Earnings

 

 2,351,421 

 

 

 2,125,980 

 

 

Accumulated Other Comprehensive Loss

 

 (40,172)

 

 

 (46,031)

 

 

Treasury Stock

 

 (306,980)

 

 

 (326,537)

 

Common Shareholders' Equity

 

 9,890,552 

 

 

 9,611,528 

Total Capitalization

 

 18,213,105 

 

 

 17,543,929 

 

 

 

 

 

 

 

 

Total Liabilities and Capitalization

$

 27,982,311 

 

$

 27,795,537 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 



2




NORTHEAST UTILITIES AND SUBSIDIARIES

 

 

 

 

 

 

 

 

 

 

 

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

 

 

 

 

 

 

 

 

 

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended September 30,

 

For the Nine Months Ended September 30,

(Thousands of Dollars, Except Share Information)

2014 

 

2013 

 

2014 

 

2013 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

$

 1,892,532 

 

$

 1,892,590 

 

$

 5,860,736 

 

$

 5,523,475 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Expenses:

 

 

 

 

 

 

 

 

 

 

 

 

Purchased Power, Fuel and Transmission

 

 716,631 

 

 

 645,881 

 

 

 2,318,993 

 

 

 1,881,992 

 

Operations and Maintenance

 

 344,092 

 

 

 386,700 

 

 

 1,069,015 

 

 

 1,089,960 

 

Depreciation

 

 153,210 

 

 

 149,105 

 

 

 456,224 

 

 

 463,635 

 

Amortization of Regulatory Assets/(Liabilities), Net

 

 (22,531)

 

 

 70,046 

 

 

 31,826 

 

 

 178,668 

 

Amortization of Rate Reduction Bonds

 

 - 

 

 

 - 

 

 

 - 

 

 

 42,581 

 

Energy Efficiency Programs

 

 118,693 

 

 

 106,097 

 

 

 360,228 

 

 

 306,010 

 

Taxes Other Than Income Taxes

 

 141,527 

 

 

 135,499 

 

 

 421,862 

 

 

 391,846 

 

 

 

Total Operating Expenses

 

 1,451,622 

 

 

 1,493,328 

 

 

 4,658,148 

 

 

 4,354,692 

Operating Income

 

 440,910 

 

 

 399,262 

 

 

 1,202,588 

 

 

 1,168,783 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Expense:

 

 

 

 

 

 

 

 

 

 

 

 

Interest on Long-Term Debt

 

 85,208 

 

 

 84,911 

 

 

 260,076 

 

 

 256,205 

 

Other Interest

 

 4,530 

 

 

 2,565 

 

 

 12,132 

 

 

 (5,622)

 

 

Interest Expense

 

 89,738 

 

 

 87,476 

 

 

 272,208 

 

 

 250,583 

Other Income, Net

 

 11,860 

 

 

 8,945 

 

 

 19,054 

 

 

 21,655 

Income Before Income Tax Expense

 

 363,032 

 

 

 320,731 

 

 

 949,434 

 

 

 939,855 

Income Tax Expense

 

 126,539 

 

 

 109,351 

 

 

 345,858 

 

 

 325,442 

Net Income

 

 236,493 

 

 

 211,380 

 

 

 603,576 

 

 

 614,413 

Net Income Attributable to Noncontrolling Interests

 

 1,879 

 

 

 1,879 

 

 

 5,639 

 

 

 5,803 

Net Income Attributable to Controlling Interest

$

 234,614 

 

$

 209,501 

 

$

 597,937 

 

$

 608,610 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic and Diluted Earnings Per Common Share

$

 0.74 

 

$

 0.66 

 

$

 1.89 

 

$

 1.93 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Dividends Declared Per Common Share

$

 0.39 

 

$

 0.37 

 

$

 1.18 

 

$

 1.10 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted Average Common Shares Outstanding:

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

 316,340,691 

 

 

 315,291,346 

 

 

 315,941,904 

 

 

 315,191,752 

 

Diluted

 

 317,554,925 

 

 

 316,218,239 

 

 

 317,186,490 

 

 

 316,061,131 

 

 

 

 

 

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 

 

 

 

 

 

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Income

$

 236,493 

 

$

 211,380 

 

$

 603,576 

 

$

 614,413 

Other Comprehensive Income, Net of Tax:

 

 

 

 

 

 

 

 

 

 

 

 

Qualified Cash Flow Hedging Instruments

 

 509 

 

 

 509 

 

 

 1,528 

 

 

 1,539 

 

Changes in Unrealized Gains/(Losses) on Other
   Securities

 

 (216)

 

 

 (38)

 

 

 242 

 

 

 (810)

 

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

 

 1,042 

 

 

 1,611 

 

 

 4,089 

 

 

 4,738 

Other Comprehensive Income, Net of Tax

 

 1,335 

 

 

 2,082 

 

 

 5,859 

 

 

 5,467 

Comprehensive Income Attributable to
   Noncontrolling Interests

 

 (1,879)

 

 

 (1,879)

 

 

 (5,639)

 

 

 (5,803)

Comprehensive Income Attributable to Controlling
   Interest

$

 235,949 

 

$

 211,583 

 

$

 603,796 

 

$

 614,077 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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




3




NORTHEAST UTILITIES AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Nine Months Ended September 30,

(Thousands of Dollars)

2014 

 

2013 

 

 

 

 

 

 

 

 

Operating Activities:

 

 

 

 

 

 

Net Income

$

 603,576 

 

$

 614,413 

 

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

 

 

 

 

 

 

 

 Depreciation

 

 456,224 

 

 

 463,635 

 

 

 Deferred Income Taxes

 

 64,755 

 

 

 334,225 

 

 

 Pension, SERP and PBOP Expense

 

 74,296 

 

 

 146,803 

 

 

 Pension and PBOP Contributions

 

 (74,681)

 

 

 (338,301)

 

 

 Regulatory Overrecoveries, Net

 

 290,111 

 

 

 66,239 

 

 

 Amortization of Regulatory Assets, Net

 

 31,826 

 

 

 178,668 

 

 

 Amortization of Rate Reduction Bonds

 

 - 

 

 

 42,581 

 

 

 Proceeds from DOE Damages Claim, Net

 

 132,138 

 

 

 - 

 

 

 Other

 

 (17,096)

 

 

 3,158 

 

Changes in Current Assets and Liabilities:

 

 

 

 

 

 

 

 Receivables and Unbilled Revenues, Net

 

 (66,463)

 

 

 (98,432)

 

 

 Fuel, Materials and Supplies

 

 (27,147)

 

 

 (13,134)

 

 

 Taxes Receivable/Accrued, Net

 

 26,533 

 

 

 (28,609)

 

 

 Accounts Payable

 

 (69,448)

 

 

 (112,512)

 

 

 Other Current Assets and Liabilities, Net

 

 (20,607)

 

 

 (81,766)

Net Cash Flows Provided by Operating Activities

 

 1,404,017 

 

 

 1,176,968 

 

 

 

 

 

 

 

 

Investing Activities:

 

 

 

 

 

 

Investments in Property, Plant and Equipment

 

 (1,117,493)

 

 

 (1,073,759)

 

Proceeds from Sales of Marketable Securities

 

 388,352 

 

 

 487,729 

 

Purchases of Marketable Securities

 

 (389,406)

 

 

 (541,070)

 

Decrease in Special Deposits

 

 - 

 

 

 69,259 

 

Other Investing Activities

 

 (4,669)

 

 

 (1,137)

Net Cash Flows Used in Investing Activities

 

 (1,123,216)

 

 

 (1,058,978)

 

 

 

 

 

 

 

 

Financing Activities:

 

 

 

 

 

 

Cash Dividends on Common Shares

 

 (356,080)

 

 

 (341,720)

 

Cash Dividends on Preferred Stock

 

 (5,639)

 

 

 (5,802)

 

Increase/(Decrease) in Notes Payable

 

 6,000 

 

 

 (172,000)

 

Issuance of Long-Term Debt

 

 650,000 

 

 

 1,350,000 

 

Retirements of Long-Term Debt

 

 (576,650)

 

 

 (840,600)

 

Retirements of Rate Reduction Bonds

 

 - 

 

 

 (82,139)

 

Other Financing Activities

 

 (90)

 

 

 (13,536)

Net Cash Flows Used in Financing Activities

 

 (282,459)

 

 

 (105,797)

Net (Decrease)/Increase in Cash and Cash Equivalents

 

 (1,658)

 

 

 12,193 

Cash and Cash Equivalents - Beginning of Period

 

 43,364 

 

 

 45,748 

Cash and Cash Equivalents - End of Period

$

 41,706 

 

$

 57,941 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 




4




THE CONNECTICUT LIGHT AND POWER COMPANY

 

 

 

 

 

CONDENSED BALANCE SHEETS

 

 

 

 

 

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30,

 

December 31,

(Thousands of Dollars)

2014 

 

2013 

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

 

Current Assets:

 

 

 

 

 

 

Cash

$

 16,294 

 

$

 7,237 

 

Receivables, Net

 

 369,492 

 

 

 319,670 

 

Accounts Receivable from Affiliated Companies

 

 35,276 

 

 

 13,777 

 

Unbilled Revenues

 

 87,806 

 

 

 92,401 

 

Regulatory Assets

 

 116,531 

 

 

 150,943 

 

Materials and Supplies

 

 47,086 

 

 

 54,606 

 

Accumulated Deferred Income Taxes

 

 52,839 

 

 

 - 

 

Prepaid Property Taxes

 

 47,429 

 

 

 13,962 

 

Prepayments and Other Current Assets

 

 17,608 

 

 

 39,120 

Total Current Assets

 

 790,361 

 

 

 691,716 

 

 

 

 

 

 

 

Property, Plant and Equipment, Net

 

 6,700,798 

 

 

 6,451,259 

 

 

 

 

 

 

 

Deferred Debits and Other Assets:

 

 

 

 

 

 

Regulatory Assets

 

 1,369,025 

 

 

 1,663,147 

 

Other Long-Term Assets

 

 178,313 

 

 

 174,380 

Total Deferred Debits and Other Assets

 

 1,547,338 

 

 

 1,837,527 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Assets

$

 9,038,497 

 

$

 8,980,502 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 




5




THE CONNECTICUT LIGHT AND POWER COMPANY

 

 

CONDENSED BALANCE SHEETS

 

 

 

 

 

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30,

 

December 31,

(Thousands of Dollars)

2014 

 

2013 

 

 

 

 

 

 

 

 

LIABILITIES AND CAPITALIZATION

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities:

 

 

 

 

 

 

Notes Payable to NU Parent

$

 105,400 

 

$

 287,300 

 

Long-Term Debt - Current Portion

 

 162,000 

 

 

 150,000 

 

Accounts Payable

 

 228,379 

 

 

 201,047 

 

Accounts Payable to Affiliated Companies

 

 46,977 

 

 

 56,531 

 

Obligations to Third Party Suppliers

 

 67,630 

 

 

 73,914 

 

Accrued Taxes

 

 54,652 

 

 

 37,186 

 

Regulatory Liabilities

 

 195,663 

 

 

 93,961 

 

Derivative Liabilities

 

 86,759 

 

 

 92,233 

 

Other Current Liabilities

 

 107,284 

 

 

 97,530 

Total Current Liabilities

 

 1,054,744 

 

 

 1,089,702 

 

 

 

 

 

 

 

 

Deferred Credits and Other Liabilities:

 

 

 

 

 

 

Accumulated Deferred Income Taxes

 

 1,581,344 

 

 

 1,510,586 

 

Regulatory Liabilities

 

 87,696 

 

 

 93,757 

 

Derivative Liabilities

 

 418,137 

 

 

 617,072 

 

Accrued Pension, SERP and PBOP

 

 63,756 

 

 

 95,895 

 

Other Long-Term Liabilities

 

 143,838 

 

 

 163,588 

Total Deferred Credits and Other Liabilities

 

 2,294,771 

 

 

 2,480,898 

 

 

 

 

 

 

 

 

Capitalization:

 

 

 

 

 

 

Long-Term Debt

 

 2,679,775 

 

 

 2,591,208 

 

 

 

 

 

 

 

 

 

Preferred Stock Not Subject to Mandatory Redemption

 

 116,200 

 

 

 116,200 

 

 

 

 

 

 

 

 

 

Common Stockholder's Equity:

 

 

 

 

 

 

 

Common Stock

 

 60,352 

 

 

 60,352 

 

 

Capital Surplus, Paid In

 

 1,804,228 

 

 

 1,682,047 

 

 

Retained Earnings

 

 1,029,473 

 

 

 961,482 

 

 

Accumulated Other Comprehensive Loss

 

 (1,046)

 

 

 (1,387)

 

Common Stockholder's Equity

 

 2,893,007 

 

 

 2,702,494 

Total Capitalization

 

 5,688,982 

 

 

 5,409,902 

 

 

 

 

 

 

 

 

Total Liabilities and Capitalization

$

 9,038,497 

 

$

 8,980,502 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 



6




THE CONNECTICUT LIGHT AND POWER COMPANY

 

 

 

 

 

 

 

 

 

CONDENSED STATEMENTS OF INCOME

 

 

 

 

 

 

 

 

 

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended September 30,

 

For the Nine Months Ended September 30,

(Thousands of Dollars)

2014 

 

2013 

 

 

2014 

 

 

2013 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

$

 695,642 

 

$

 648,420 

 

$

 2,017,580 

 

$

 1,841,846 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Expenses:

 

 

 

 

 

 

 

 

 

 

 

 

Purchased Power and Transmission

 

 255,787 

 

 

 253,152 

 

 

 736,952 

 

 

 667,266 

 

Operations and Maintenance

 

 127,285 

 

 

 127,104 

 

 

 368,562 

 

 

 359,759 

 

Depreciation

 

 46,886 

 

 

 44,786 

 

 

 139,598 

 

 

 132,356 

 

Amortization of Regulatory Assets/(Liabilities), Net

 

 13,098 

 

 

 (27)

 

 

 62,644 

 

 

 11,223 

 

Energy Efficiency Programs

 

 41,399 

 

 

 24,544 

 

 

 119,389 

 

 

 68,211 

 

Taxes Other Than Income Taxes

 

 64,994 

 

 

 64,979 

 

 

 194,105 

 

 

 182,676 

 

 

Total Operating Expenses

 

 549,449 

 

 

 514,538 

 

 

 1,621,250 

 

 

 1,421,491 

Operating Income

 

 146,193 

 

 

 133,882 

 

 

 396,330 

 

 

 420,355 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Expense:

 

 

 

 

 

 

 

 

 

 

 

 

Interest on Long-Term Debt

 

 34,743 

 

 

 32,845 

 

 

 102,290 

 

 

 98,163 

 

Other Interest

 

 3,992 

 

 

 2,439 

 

 

 8,158 

 

 

 801 

 

 

Interest Expense

 

 38,735 

 

 

 35,284 

 

 

 110,448 

 

 

 98,964 

Other Income, Net

 

 6,456 

 

 

 3,861 

 

 

 10,658 

 

 

 10,946 

Income Before Income Tax Expense

 

 113,914 

 

 

 102,459 

 

 

 296,540 

 

 

 332,337 

Income Tax Expense

 

 30,038 

 

 

 36,136 

 

 

 95,980 

 

 

 113,149 

Net Income

$

 83,876 

 

$

 66,323 

 

$

 200,560 

 

$

 219,188 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

 

 

 

 

 

 

 

 

 

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Income

$

 83,876 

 

$

 66,323 

 

$

 200,560 

 

$

 219,188 

Other Comprehensive Income, Net of Tax:

 

 

 

 

 

 

 

 

 

 

 

 

Qualified Cash Flow Hedging Instruments

 

 111 

 

 

 111 

 

 

 333 

 

 

 333 

 

Changes in Unrealized Gains/(Losses) on Other
   Securities

 

 (7)

 

 

 (1)

 

 

 8 

 

 

 (27)

Other Comprehensive Income, Net of Tax

 

 104 

 

 

 110 

 

 

 341 

 

 

 306 

Comprehensive Income

$

 83,980 

 

$

 66,433 

 

$

 200,901 

 

$

 219,494 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 



7




THE CONNECTICUT LIGHT AND POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Nine Months Ended September 30,

(Thousands of Dollars)

2014 

 

2013 

 

 

 

 

 

 

 

 

Operating Activities:

 

 

 

 

 

 

Net Income

$

 200,560 

 

$

 219,188 

 

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

 

 

 

 

 

 

 

 Depreciation

 

 139,598 

 

 

 132,356 

 

 

 Deferred Income Taxes

 

 (14,400)

 

 

 89,084 

 

 

 Pension, SERP and PBOP Expense, Net of PBOP Contributions

 

 8,050 

 

 

 16,182 

 

 

 Regulatory Overrecoveries, Net

 

 62,929 

 

 

 24,061 

 

 

 Amortization of Regulatory Assets, Net

 

 62,644 

 

 

 11,223 

 

 

 Proceeds from DOE Damages Claim

 

 68,610 

 

 

 - 

 

 

 Other

 

 (11,290)

 

 

 (8,759)

 

Changes in Current Assets and Liabilities:

 

 

 

 

 

 

 

 Receivables and Unbilled Revenues, Net

 

 (87,922)

 

 

 (44,523)

 

 

 Taxes Receivable/Accrued, Net

 

 39,805 

 

 

 841 

 

 

 Accounts Payable

 

 16,984 

 

 

 (101,949)

 

 

 Other Current Assets and Liabilities, Net

 

 (2,575)

 

 

 (29,106)

Net Cash Flows Provided by Operating Activities

 

 482,993 

 

 

 308,598 

 

 

 

 

 

 

 

 

Investing Activities:

 

 

 

 

 

 

Investments in Property, Plant and Equipment

 

 (371,660)

 

 

 (294,638)

 

Other Investing Activities

 

 (4,539)

 

 

 2,013 

Net Cash Flows Used in Investing Activities

 

 (376,199)

 

 

 (292,625)

 

 

 

 

 

 

 

 

Financing Activities:

 

 

 

 

 

 

Cash Dividends on Common Stock

 

 (128,400)

 

 

 (114,000)

 

Cash Dividends on Preferred Stock

 

 (4,169)

 

 

 (4,169)

 

Issuance of Long-Term Debt

 

 250,000 

 

 

 400,000 

 

Retirements of Long-Term Debt

 

 (150,000)

 

 

 (125,000)

 

Decrease in Notes Payable to NU Parent

 

 (181,900)

 

 

 (62,200)

 

Capital Contribution from NU Parent

 

 120,000 

 

 

 - 

 

Decrease in Short-Term Debt

 

 - 

 

 

 (89,000)

 

Other Financing Activities

 

 (3,268)

 

 

 (6,352)

Net Cash Flows Used in Financing Activities

 

 (97,737)

 

 

 (721)

Net Increase in Cash

 

 9,057 

 

 

 15,252 

Cash - Beginning of Period

 

 7,237 

 

 

 1 

Cash - End of Period

$

 16,294 

 

$

 15,253 

 

 

 

 

 

 

 

 

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




8




NSTAR ELECTRIC COMPANY AND SUBSIDIARY

 

 

 

 

 

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

 

 

 

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30,

 

December 31,

(Thousands of Dollars)

2014 

 

2013 

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

 

Current Assets:

 

 

 

 

 

 

Cash and Cash Equivalents

$

 11,040 

 

$

 8,021 

 

Receivables, Net

 

 275,902 

 

 

 209,711 

 

Accounts Receivable from Affiliated Companies

 

 47,215 

 

 

 27,264 

 

Unbilled Revenues

 

 39,372 

 

 

 41,368 

 

Materials and Supplies

 

 65,073 

 

 

 44,236 

 

Regulatory Assets

 

 128,205 

 

 

 204,144 

 

Prepayments and Other Current Assets

 

 11,267 

 

 

 36,710 

Total Current Assets

 

 578,074 

 

 

 571,454 

 

 

 

 

 

 

 

Property, Plant and Equipment, Net

 

 5,211,681 

 

 

 5,043,887 

 

 

 

 

 

 

 

Deferred Debits and Other Assets:

 

 

 

 

 

 

Regulatory Assets

 

 998,030 

 

 

 1,235,156 

 

Other Long-Term Assets

 

 62,644 

 

 

 60,624 

Total Deferred Debits and Other Assets

 

 1,060,674 

 

 

 1,295,780 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Assets

$

 6,850,429 

 

$

 6,911,121 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 



9




NSTAR ELECTRIC COMPANY AND SUBSIDIARY

 

 

 

 

 

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

 

 

 

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30,

 

December 31,

(Thousands of Dollars)

2014 

 

2013 

 

 

 

 

 

 

 

 

LIABILITIES AND CAPITALIZATION

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities:

 

 

 

 

 

 

Notes Payable

$

 159,500 

 

$

103,500 

 

Long-Term Debt - Current Portion

 

 4,700 

 

 

301,650 

 

Accounts Payable

 

 128,056 

 

 

202,100 

 

Accounts Payable to Affiliated Companies

 

 62,625 

 

 

75,707 

 

Obligations to Third Party Suppliers

 

 37,298 

 

 

5,459 

 

Power Contract Obligations

 

 35,783 

 

 

30,842 

 

Renewable Portfolio Standards Compliance Obligations

 

 34,905 

 

 

 39,686 

 

Accrued Taxes

 

 42,338 

 

 

7,946 

 

Accumulated Deferred Income Taxes

 

 9,622 

 

 

 50,128 

 

Regulatory Liabilities

 

 97,215 

 

 

 53,958 

 

Other Current Liabilities

 

 62,436 

 

 

 39,936 

Total Current Liabilities

 

 674,478 

 

 

 910,912 

 

 

 

 

 

 

 

 

Deferred Credits and Other Liabilities:

 

 

 

 

 

 

Accumulated Deferred Income Taxes

 

 1,425,306 

 

 

 1,466,835 

 

Regulatory Liabilities

 

 266,524 

 

 

 253,108 

 

Accrued Pension, SERP and PBOP

 

 142,249 

 

 

 118,010 

 

Payable to Affiliated Companies

 

 - 

 

 

 64,172 

 

Other Long-Term Liabilities

 

 112,853 

 

 

 142,214 

Total Deferred Credits and Other Liabilities

 

 1,946,932 

 

 

 2,044,339 

 

 

 

 

 

 

 

 

Capitalization:

 

 

 

 

 

 

Long-Term Debt

 

 1,792,707 

 

 

 1,499,417 

 

 

 

 

 

 

 

 

 

Preferred Stock Not Subject to Mandatory Redemption

 

 43,000 

 

 

 43,000 

 

 

 

 

 

 

 

 

 

Common Stockholder's Equity:

 

 

 

 

 

 

 

Common Stock

 

 - 

 

 

 - 

 

 

Capital Surplus, Paid In

 

 993,163 

 

 

 992,625 

 

 

Retained Earnings

 

 1,400,149 

 

 

 1,420,828 

 

Common Stockholder's Equity

 

 2,393,312 

 

 

 2,413,453 

Total Capitalization

 

 4,229,019 

 

 

 3,955,870 

 

 

 

 

 

 

 

 

Total Liabilities and Capitalization

$

 6,850,429 

 

$

 6,911,121 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 



10




NSTAR ELECTRIC COMPANY AND SUBSIDIARY

 

 

 

 

 

 

 

 

 

 

 

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

 

 

 

 

 

 

 

 

 

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended September 30,

 

For the Nine Months Ended September 30,

(Thousands of Dollars)

2014 

 

2013 

 

 

2014 

 

 

2013 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

$

 727,909 

 

$

 753,879 

 

$

 1,955,609 

 

$

 1,916,557 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Expenses:

 

 

 

 

 

 

 

 

 

 

 

 

Purchased Power and Transmission

 

 317,784 

 

 

 255,244 

 

 

 879,773 

 

 

659,140 

 

Operations and Maintenance

 

 79,705 

 

 

 97,069 

 

 

 244,610 

 

 

277,261 

 

Depreciation

 

 47,455 

 

 

 45,441 

 

 

 140,996 

 

 

136,323 

 

Amortization of Regulatory Assets/(Liabilities), Net

 

 (15,063)

 

 

 72,740 

 

 

 (916)

 

 

173,289 

 

Amortization of Rate Reduction Bonds

 

 - 

 

 

 - 

 

 

 - 

 

 

15,054 

 

Energy Efficiency Programs

 

 56,915 

 

 

 58,798 

 

 

 145,499 

 

 

161,180 

 

Taxes Other Than Income Taxes

 

 34,513 

 

 

 32,610 

 

 

 99,121 

 

 

95,275 

 

 

Total Operating Expenses

 

 521,309 

 

 

 561,902 

 

 

 1,509,083 

 

 

1,517,522 

Operating Income

 

 206,600 

 

 

 191,977 

 

 

 446,526 

 

 

399,035 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Expense:

 

 

 

 

 

 

 

 

 

 

 

 

Interest on Long-Term Debt

 

 17,996 

 

 

 19,860 

 

 

 58,485 

 

 

59,261 

 

Other Interest

 

 (658)

 

 

 (1,324)

 

 

 606 

 

 

(7,612)

 

 

Interest Expense

 

 17,338 

 

 

 18,536 

 

 

 59,091 

 

 

51,649 

Other Income, Net

 

 3,287 

 

 

 2,126 

 

 

 3,011 

 

 

3,275 

Income Before Income Tax Expense

 

 192,549 

 

 

 175,567 

 

 

 390,446 

 

 

 350,661 

Income Tax Expense

 

 76,975 

 

 

 68,558 

 

 

 156,655 

 

 

137,499 

Net Income

$

 115,574 

 

$

 107,009 

 

$

 233,791 

 

$

 213,162 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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



11




NSTAR ELECTRIC COMPANY AND SUBSIDIARY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Nine Months Ended September 30,

(Thousands of Dollars)

2014 

 

2013 

 

 

 

 

 

 

 

 

Operating Activities:

 

 

 

 

 

 

Net Income

$

 233,791 

 

$

 213,162 

 

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

 

 

 

 

 

 

 

 Depreciation

 

 140,996 

 

 

 136,323 

 

 

 Deferred Income Taxes

 

 (39,399)

 

 

 26,358 

 

 

 Pension and PBOP Expense, Net of Contributions

 

 (11,046)

 

 

 (55,195)

 

 

 Regulatory Over/(Under) Recoveries, Net

 

 155,357 

 

 

 (11,299)

 

 

 Amortization of Regulatory Assets, Net

 

 (916)

 

 

 173,289 

 

 

 Amortization of Rate Reduction Bonds

 

 - 

 

 

 15,054 

 

 

 Proceeds from DOE Damages Claim

 

 30,193 

 

 

 - 

 

 

 Bad Debt Expense

 

 15,250 

 

 

 19,012 

 

 

 Other

 

 (56,851)

 

 

 (48,291)

 

Changes in Current Assets and Liabilities:

 

 

 

 

 

 

 

 Receivables and Unbilled Revenues, Net

 

 (47,770)

 

 

 (80,575)

 

 

 Materials and Supplies

 

 (20,837)

 

 

 7,961 

 

 

 Taxes Receivable/Accrued, Net

 

 60,252 

 

 

 (6,345)

 

 

 Accounts Payable

 

 (40,594)

 

 

 6,856 

 

 

 Accounts Receivable from/Payable to Affiliates, Net

 

 66,758 

 

 

 (59,173)

 

 

 Other Current Assets and Liabilities, Net

 

 32,340 

 

 

 (19,547)

Net Cash Flows Provided by Operating Activities

 

 517,524 

 

 

 317,590 

 

 

 

 

 

 

 

 

Investing Activities:

 

 

 

 

 

 

Investments in Property, Plant and Equipment

 

 (309,248)

 

 

 (330,635)

 

Decrease in Special Deposits

 

 - 

 

 

 37,899 

 

Other Investing Activities

 

 - 

 

 

 575 

Net Cash Flows Used in Investing Activities

 

 (309,248)

 

 

 (292,161)

 

 

 

 

 

 

 

 

Financing Activities:

 

 

 

 

 

 

Cash Dividends on Common Stock

 

 (253,000)

 

 

 (56,000)

 

Cash Dividends on Preferred Stock

 

 (1,470)

 

 

 (1,633)

 

Increase/(Decrease) in Notes Payable

 

 56,000 

 

 

 (120,000)

 

Issuance of Long-Term Debt

 

 300,000 

 

 

 200,000 

 

Retirements of Long-Term Debt

 

 (301,650)

 

 

 (1,650)

 

Retirements of Rate Reduction Bonds

 

 - 

 

 

 (43,493)

 

Other Financing Activities

 

 (5,137)

 

 

 (878)

Net Cash Flows Used in Financing Activities

 

 (205,257)

 

 

 (23,654)

Net Increase in Cash and Cash Equivalents

 

 3,019 

 

 

 1,775 

Cash and Cash Equivalents - Beginning of Period

 

 8,021 

 

 

 13,695 

Cash and Cash Equivalents - End of Period

$

 11,040 

 

$

 15,470 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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




12




PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY

 

 

 

 

 

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

 

 

 

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30,

 

December 31,

(Thousands of Dollars)

2014 

 

2013 

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

 

Current Assets:

 

 

 

 

 

 

Cash

$

 2,750 

 

$

 130 

 

Receivables, Net

 

 77,602 

 

 

 76,331 

 

Accounts Receivable from Affiliated Companies

 

 6,271 

 

 

 90 

 

Unbilled Revenues

 

 33,088 

 

 

 38,344 

 

Fuel, Materials and Supplies

 

 141,381 

 

 

 128,736 

 

Regulatory Assets

 

 102,473 

 

 

 92,194 

 

Prepayments and Other Current Assets

 

 22,270 

 

 

 24,100 

Total Current Assets

 

 385,835 

 

 

 359,925 

 

 

 

 

 

 

 

Property, Plant and Equipment, Net

 

 2,560,635 

 

 

 2,467,556 

 

 

 

 

 

 

 

Deferred Debits and Other Assets:

 

 

 

 

 

 

Regulatory Assets

 

 178,204 

 

 

 219,346 

 

Other Long-Term Assets

 

 54,748 

 

 

 39,891 

Total Deferred Debits and Other Assets

 

 232,952 

 

 

 259,237 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Assets

 $

 3,179,422 

 

 $

 3,086,718 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 




13




PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY

 

 

 

 

 

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

 

 

 

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30,

 

December 31,

(Thousands of Dollars)

2014 

 

2013 

 

 

 

 

 

 

 

 

LIABILITIES AND CAPITALIZATION

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities:

 

 

 

 

 

 

Notes Payable to NU Parent

$

 153,300 

 

$

 86,500 

 

Long-Term Debt - Current Portion

 

 - 

 

 

 50,000 

 

Accounts Payable

 

 58,801 

 

 

 82,920 

 

Accounts Payable to Affiliated Companies

 

 22,932 

 

 

 22,040 

 

Regulatory Liabilities

 

 29,165 

 

 

 20,643 

 

Accumulated Deferred Income Taxes

 

 29,936 

 

 

 28,596 

 

Other Current Liabilities

 

 38,725 

 

 

 51,729 

Total Current Liabilities

 

 332,859 

 

 

 342,428 

 

 

 

 

 

 

 

 

Deferred Credits and Other Liabilities:

 

 

 

 

 

 

Accumulated Deferred Income Taxes

 

 566,298 

 

 

 500,166 

 

Regulatory Liabilities

 

 50,614 

 

 

 51,723 

 

Accrued SERP and PBOP

 

 14,320 

 

 

 15,272 

 

Other Long-Term Liabilities

 

 46,874 

 

 

 46,247 

Total Deferred Credits and Other Liabilities

 

 678,106 

 

 

 613,408 

 

 

 

 

 

 

 

 

Capitalization:

 

 

 

 

 

 

Long-Term Debt

 

 999,230 

 

 

 999,006 

 

 

 

 

 

 

 

 

 

Common Stockholder's Equity:

 

 

 

 

 

 

 

Common Stock

 

 - 

 

 

 - 

 

 

Capital Surplus, Paid In

 

 702,923 

 

 

 701,911 

 

 

Retained Earnings

 

 473,969 

 

 

 438,515 

 

 

Accumulated Other Comprehensive Loss

 

 (7,665)

 

 

 (8,550)

 

Common Stockholder's Equity

 

 1,169,227 

 

 

 1,131,876 

Total Capitalization

 

 2,168,457 

 

 

 2,130,882 

 

 

 

 

 

 

 

 

Total Liabilities and Capitalization

$

 3,179,422 

 

$

 3,086,718 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 




14






PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY

 

 

 

 

 

 

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

 

 

 

 

 

 

 

 

 

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended September 30,

 

For the Nine Months Ended September 30,

(Thousands of Dollars)

2014 

 

2013 

 

2014 

 

 

2013 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

$

 223,664 

 

$

 218,608 

 

$

 735,123 

 

$

 708,550 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Expenses:

 

 

 

 

 

 

 

 

 

 

 

 

Purchased Power, Fuel and Transmission

 

 64,397 

 

 

 46,668 

 

 

 247,992 

 

 

 197,765 

 

Operations and Maintenance

 

 65,563 

 

 

 69,477 

 

 

 198,025 

 

 

 191,606 

 

Depreciation

 

 24,568 

 

 

 22,919 

 

 

 73,247 

 

 

 68,433 

 

Amortization of Regulatory Assets/(Liabilities), Net

 

 (9,734)

 

 

 225 

 

 

 (17,565)

 

 

 (1,745)

 

Amortization of Rate Reduction Bonds

 

 - 

 

 

 - 

 

 

 - 

 

 

 19,748 

 

Energy Efficiency Programs

 

 3,766 

 

 

 3,990 

 

 

 10,897 

 

 

 11,036 

 

Taxes Other Than Income Taxes

 

 18,702 

 

 

 18,706 

 

 

 53,051 

 

 

 52,640 

 

 

Total Operating Expenses

 

 167,262 

 

 

 161,985 

 

 

 565,647 

 

 

 539,483 

Operating Income

 

 56,402 

 

 

 56,623 

 

 

 169,476 

 

 

 169,067 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Expense:

 

 

 

 

 

 

 

 

 

 

 

 

Interest on Long-Term Debt

 

 10,896 

 

 

 10,345 

 

 

 33,812 

 

 

 32,951 

 

Other Interest

 

 128 

 

 

 521 

 

 

 183 

 

 

 1,230 

 

 

Interest Expense

 

 11,024 

 

 

 10,866 

 

 

 33,995 

 

 

 34,181 

Other Income, Net

 

 461 

 

 

 792 

 

 

 1,673 

 

 

 2,454 

Income Before Income Tax Expense

 

 45,839 

 

 

 46,549 

 

 

 137,154 

 

 

 137,340 

Income Tax Expense

 

 17,603 

 

 

 18,196 

 

 

 52,199 

 

 

 52,797 

Net Income

$

 28,236 

 

$

 28,353 

 

$

 84,955 

 

$

 84,543 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 

 

 

 

 

 

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Income

$

 28,236 

 

$

 28,353 

 

$

 84,955 

 

$

 84,543 

Other Comprehensive Income, Net of Tax:

 

 

 

 

 

 

 

 

 

 

 

 

Qualified Cash Flow Hedging Instruments

 

 290 

 

 

290 

 

 

 871 

 

 

872 

 

Changes in Unrealized Gains/(Losses) on Other
   Securities

 

 (13)

 

 

 (2)

 

 

 14 

 

 

 (47)

 

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

 

 - 

 

 

 - 

 

 

 - 

 

 

 (3)

Other Comprehensive Income, Net of Tax

 

 277 

 

 

288 

 

 

 885 

 

 

822 

Comprehensive Income

$

 28,513 

 

$

 28,641 

 

$

 85,840 

 

$

 85,365 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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




15






PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Nine Months Ended September 30,

(Thousands of Dollars)

2014 

 

2013 

 

 

 

 

 

 

 

 

Operating Activities:

 

 

 

 

 

 

Net Income

$

 84,955 

 

$

 84,543 

 

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

 

 

 

 

 

 

 

 Depreciation

 

 73,247 

 

 

 68,433 

 

 

 Deferred Income Taxes

 

 67,827 

 

 

 57,066 

 

 

 Pension, SERP and PBOP Expense

 

 4,541 

 

 

 20,427 

 

 

 Pension and PBOP Contributions

 

 (1,637)

 

 

 (112,964)

 

 

 Regulatory Over/(Under) Recoveries, Net

 

 16,813 

 

 

 (1,346)

 

 

 Amortization of Regulatory Liabilities, Net

 

 (17,565)

 

 

 (1,745)

 

 

 Amortization of Rate Reduction Bonds

 

 - 

 

 

 19,748 

 

 

 Proceeds from DOE Damages Claim

 

 14,453 

 

 

 - 

 

 

 Other

 

 7,930 

 

 

 7,165 

 

Changes in Current Assets and Liabilities:

 

 

 

 

 

 

 

 Receivables and Unbilled Revenues, Net

 

 (7,467)

 

 

 8,047 

 

 

 Fuel, Materials and Supplies

 

 (17,350)

 

 

 (30,456)

 

 

 Taxes Receivable/Accrued, Net

 

 (24,108)

 

 

 5,103 

 

 

 Accounts Payable

 

 (9,297)

 

 

 29,148 

 

 

 Other Current Assets and Liabilities, Net

 

 13,470 

 

 

 7,220 

Net Cash Flows Provided by Operating Activities

 

 205,812 

 

 

 160,389 

 

 

 

 

 

 

 

 

Investing Activities:

 

 

 

 

 

 

Investments in Property, Plant and Equipment

 

 (170,127)

 

 

 (155,676)

 

(Increase)/Decrease in Special Deposits

 

 (45)

 

 

 22,039 

 

Other Investing Activities

 

 (103)

 

 

 (53)

Net Cash Flows Used in Investing Activities

 

 (170,275)

 

 

 (133,690)

 

 

 

 

 

 

 

 

Financing Activities:

 

 

 

 

 

 

Cash Dividends on Common Stock

 

 (49,500)

 

 

 (51,000)

 

Increase in Notes Payable to NU Parent

 

 66,800 

 

 

 165,200 

 

Retirements of Long-Term Debt

 

 (50,000)

 

 

 (108,950)

 

Retirements of Rate Reduction Bonds

 

 - 

 

 

 (29,294)

 

Other Financing Activities

 

 (217)

 

 

 456 

Net Cash Flows Used in Financing Activities

 

 (32,917)

 

 

 (23,588)

Net Increase in Cash

 

 2,620 

 

 

 3,111 

Cash - Beginning of Period

 

 130 

 

 

 2,493 

Cash - End of Period

$

 2,750 

 

$

 5,604 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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




16




WESTERN MASSACHUSETTS ELECTRIC COMPANY

 

 

 

 

 

CONDENSED BALANCE SHEETS

 

 

 

 

 

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30,

 

December 31,

(Thousands of Dollars)

2014 

 

2013 

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

 

Current Assets:

 

 

 

 

 

 

Cash

$

 1,737 

 

$

 - 

 

Receivables, Net

 

 50,835 

 

 

 49,018 

 

Accounts Receivable from Affiliated Companies

 

 14,522 

 

 

 47,607 

 

Unbilled Revenues

 

 12,664 

 

 

 16,562 

 

Taxes Receivable

 

 11,504 

 

 

 432 

 

Regulatory Assets

 

 38,907 

 

 

 43,024 

 

Marketable Securities

 

 22,107 

 

 

 26,628 

 

Prepayments and Other Current Assets

 

 6,688 

 

 

 10,479 

Total Current Assets

 

 158,964 

 

 

 193,750 

 

 

 

 

 

 

 

Property, Plant and Equipment, Net

 

 1,432,368 

 

 

 1,381,060 

 

 

 

 

 

 

 

Deferred Debits and Other Assets:

 

 

 

 

 

 

Regulatory Assets

 

 109,690 

 

 

 146,088 

 

Marketable Securities

 

 35,963 

 

 

 31,243 

 

Other Long-Term Assets

 

 50,902 

 

 

 40,679 

Total Deferred Debits and Other Assets

 

 196,555 

 

 

 218,010 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Assets

$

 1,787,887 

 

$

 1,792,820 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 



17




WESTERN MASSACHUSETTS ELECTRIC COMPANY

CONDENSED BALANCE SHEETS

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30,

 

December 31,

(Thousands of Dollars)

2014 

 

2013 

 

 

 

 

 

 

 

 

LIABILITIES AND CAPITALIZATION

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities:

 

 

 

 

 

 

Notes Payable to NU Parent

$

 13,200 

 

$

 - 

 

Long-Term Debt - Current Portion

 

 50,000 

 

 

 - 

 

Accounts Payable

 

 36,558 

 

 

 62,961 

 

Accounts Payable to Affiliated Companies

 

 13,312 

 

 

 9,230 

 

Accrued Interest

 

 2,839 

 

 

 7,525 

 

Regulatory Liabilities

 

 43,462 

 

 

 19,858 

 

Accumulated Deferred Income Taxes

 

 1,920 

 

 

 13,098 

 

Counterparty Deposits

 

 626 

 

 

 7,688 

 

Other Current Liabilities

 

 11,758 

 

 

 20,629 

Total Current Liabilities

 

 173,675 

 

 

 140,989 

 

 

 

 

 

 

 

 

Deferred Credits and Other Liabilities:

 

 

 

 

 

 

Accumulated Deferred Income Taxes

 

 413,701 

 

 

 396,933 

 

Regulatory Liabilities

 

 10,289 

 

 

 13,873 

 

Accrued SERP and PBOP

 

 2,623 

 

 

 3,911 

 

Other Long-Term Liabilities

 

 38,372 

 

 

 28,619 

Total Deferred Credits and Other Liabilities

 

 464,985 

 

 

 443,336 

 

 

 

 

 

 

 

 

Capitalization:

 

 

 

 

 

 

Long-Term Debt

 

 578,686 

 

 

 629,389 

 

 

 

 

 

 

 

 

 

Common Stockholder's Equity:

 

 

 

 

 

 

 

Common Stock

 

 10,866 

 

 

 10,866 

 

 

Capital Surplus, Paid In

 

 391,136 

 

 

 390,743 

 

 

Retained Earnings

 

 171,800 

 

 

 181,014 

 

 

Accumulated Other Comprehensive Loss

 

 (3,261)

 

 

 (3,517)

 

Common Stockholder's Equity

 

 570,541 

 

 

 579,106 

Total Capitalization

 

 1,149,227 

 

 

 1,208,495 

 

 

 

 

 

 

 

 

Total Liabilities and Capitalization

$

 1,787,887 

 

$

 1,792,820 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 



18




WESTERN MASSACHUSETTS ELECTRIC COMPANY

 

 

 

 

 

 

 

 

 

CONDENSED STATEMENTS OF INCOME

 

 

 

 

 

 

 

 

 

 

 

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended September 30,

 

For the Nine Months Ended September 30,

(Thousands of Dollars)

2014 

 

2013 

 

2014 

 

2013 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

$

 118,145 

 

$

 121,795 

 

$

 363,843 

 

$

 361,763 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Expenses:

 

 

 

 

 

 

 

 

 

 

 

 

Purchased Power and Transmission

 

 43,926 

 

 

 38,797 

 

 

 130,977 

 

 

 111,095 

 

Operations and Maintenance

 

 20,820 

 

 

 26,148 

 

 

 67,085 

 

 

 70,213 

 

Depreciation

 

 10,506 

 

 

 9,426 

 

 

 31,144 

 

 

 27,707 

 

Amortization of Regulatory Liabilities, Net

 

 (8,519)

 

 

 (1,412)

 

 

 (7,778)

 

 

 (598)

 

Amortization of Rate Reduction Bonds

 

 - 

 

 

 - 

 

 

 - 

 

 

 7,780 

 

Energy Efficiency Programs

 

 10,983 

 

 

 12,222 

 

 

 33,096 

 

 

 28,462 

 

Taxes Other Than Income Taxes

 

 9,200 

 

 

 7,696 

 

 

 25,679 

 

 

 20,188 

 

 

Total Operating Expenses

 

 86,916 

 

 

 92,877 

 

 

 280,203 

 

 

 264,847 

Operating Income

 

 31,229 

 

 

 28,918 

 

 

 83,640 

 

 

 96,916 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Expense:

 

 

 

 

 

 

 

 

 

 

 

 

Interest on Long-Term Debt

 

 6,029 

 

 

 5,814 

 

 

 18,195 

 

 

 17,846 

 

Other Interest

 

 547 

 

 

 417 

 

 

 734 

 

 

 954 

 

 

Interest Expense

 

 6,576 

 

 

 6,231 

 

 

 18,929 

 

 

 18,800 

Other Income, Net

 

 502 

 

 

 926 

 

 

 1,670 

 

 

 2,349 

Income Before Income Tax Expense

 

 25,155 

 

 

 23,613 

 

 

 66,381 

 

 

 80,465 

Income Tax Expense

 

 10,490 

 

 

 8,588 

 

 

 26,596 

 

 

 30,424 

Net Income

$

 14,665 

 

$

 15,025 

 

$

 39,785 

 

$

 50,041 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 



CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

 

 

 

 

 

 

 

 

 

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Income

$

 14,665 

 

$

 15,025 

 

$

 39,785 

 

$

 50,041 

Other Comprehensive Income, Net of Tax:

 

 

 

 

 

 

 

 

 

 

 

 

Qualified Cash Flow Hedging Instruments

 

 85 

 

 

85 

 

 

 254 

 

 

254 

 

Changes in Unrealized Gains/(Losses) on Other
   Securities

 

 (2)

 

 

 - 

 

 

 2 

 

 

 (8)

Other Comprehensive Income, Net of Tax

 

 83 

 

 

 85 

 

 

 256 

 

 

 246 

Comprehensive Income

$

 14,748 

 

$

 15,110 

 

$

 40,041 

 

$

 50,287 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 




19




WESTERN MASSACHUSETTS ELECTRIC COMPANY

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Nine Months Ended September 30,

(Thousands of Dollars)

2014 

 

2013 

 

 

 

 

 

 

 

 

Operating Activities:

 

 

 

 

 

 

Net Income

$

 39,785 

 

$

 50,041 

 

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

 

 

 

 

 

 

 

 Depreciation

 

 31,144 

 

 

 27,707 

 

 

 Deferred Income Taxes

 

 13,479 

 

 

 79,401 

 

 

 Regulatory Overrecoveries, Net

 

 33,630 

 

 

 11,685 

 

 

 Amortization of Regulatory Liabilities, Net

 

 (7,778)

 

 

 (598)

 

 

 Amortization of Rate Reduction Bonds

 

 - 

 

 

 7,780 

 

 

 Proceeds from DOE Damages Claim

 

 18,883 

 

 

 - 

 

 

 Other

 

 615 

 

 

 (544)

 

Changes in Current Assets and Liabilities:

 

 

 

 

 

 

 

 Receivables and Unbilled Revenues, Net

 

 36,075 

 

 

 (32,231)

 

 

 Taxes Receivable/Accrued, Net

 

 (15,831)

 

 

 16,412 

 

 

 Accounts Payable

 

 (12,847)

 

 

 20,260 

 

 

 Other Current Assets and Liabilities, Net

 

 (16,551)

 

 

 (9,857)

Net Cash Flows Provided by Operating Activities

 

 120,604 

 

 

 170,056 

 

 

 

 

 

 

 

 

Investing Activities:

 

 

 

 

 

 

Investments in Property, Plant and Equipment

 

 (82,546)

 

 

 (127,352)

 

Proceeds from Sales of Marketable Securities

 

 58,788 

 

 

 53,552 

 

Purchases of Marketable Securities

 

 (59,280)

 

 

 (54,042)

 

Other Investing Activities

 

 - 

 

 

 7,401 

Net Cash Flows Used in Investing Activities

 

 (83,038)

 

 

 (120,441)

 

 

 

 

 

 

 

 

Financing Activities:

 

 

 

 

 

 

Cash Dividends on Common Stock

 

 (49,000)

 

 

 (30,000)

 

Retirement of Long-Term Debt

 

 - 

 

 

 (55,000)

 

Increase in Notes Payable to NU Parent

 

 13,200 

 

 

 47,900 

 

Retirement of Rate Reduction Bonds

 

 - 

 

 

 (9,352)

 

Other Financing Activities

 

 (29)

 

 

 (7)

Net Cash Flows Used in Financing Activities

 

 (35,829)

 

 

 (46,459)

Net Increase in Cash

 

 1,737 

 

 

 3,156 

Cash - Beginning of Period

 

 - 

 

 

 1 

Cash - End of Period

$

 1,737 

 

$

 3,157 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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




20



NORTHEAST UTILITIES AND SUBSIDIARIES

THE CONNECTICUT LIGHT AND POWER COMPANY

NSTAR ELECTRIC COMPANY AND SUBSIDIARY

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY

WESTERN MASSACHUSETTS ELECTRIC COMPANY


COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)


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


1.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES


A.

Basis of Presentation

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


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


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


The financial statements contain, in the opinion of management, all adjustments (including normal, recurring adjustments) necessary to present fairly NU's, CL&P's, NSTAR Electric's, PSNH's and WMECO's financial position as of September 30, 2014 and December 31, 2013, the results of operations and comprehensive income for the three and nine months ended September 30, 2014 and 2013, and the cash flows for the nine months ended September 30, 2014 and 2013.  The results of operations and comprehensive income for the three and nine months ended September 30, 2014 and 2013, and the cash flows for the nine months ended September 30, 2014 and 2013 are not necessarily indicative of the results expected for a full year.  


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


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


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


B.

Accounting Standards

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


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




21




C.

Provision for Uncollectible Accounts

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


(Millions of Dollars)

 

As of September 30, 2014

 

As of December 31, 2013

NU

 

$

181.4 

 

$

171.3 

CL&P

 

 

85.8 

 

 

82.0 

NSTAR Electric

 

 

42.3 

 

 

41.7 

PSNH

 

 

7.9 

 

 

7.4 

WMECO

 

 

11.1 

 

 

10.0 


D.

Fair Value Measurements

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


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


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


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


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


Determination of Fair Value:  The valuation techniques and inputs used in NU's fair value measurements are described in Note 4, "Derivative Instruments," Note 5, "Marketable Securities," and Note 10, "Fair Value of Financial Instruments," to the financial statements.


E.

Other Income, Net

Items included within Other Income, Net on the statements of income primarily consist of investment income/(loss), interest income, AFUDC related to equity funds, and equity in earnings.  Investment income/(loss) primarily relates to debt and equity securities held in trust.  For further information, see Note 5, "Marketable Securities," to the financial statements.  


F.

Other Taxes

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


 

For the Three Months Ended

 

For the Nine Months Ended

(Millions of Dollars)

September 30, 2014

 

September 30, 2013

 

September 30, 2014

 

September 30, 2013

NU

$

35.0 

 

$

 37.5 

 

$

114.6 

 

$

 108.9 

CL&P

 

32.5 

 

 

 35.5 

 

 

99.0 

 

 

 97.3 


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




22




G.

 

     Supplemental Cash Flow Information

 

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


(Millions of Dollars)

As of September 30, 2014

 

As of September 30, 2013

NU

$

128.9 

 

$

122.9 

CL&P

 

52.2 

 

 

36.6 

NSTAR Electric

 

18.1 

 

 

31.9 

PSNH

 

21.0 

 

 

16.9 

WMECO

 

10.0 

 

 

13.8 


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


H.

Severance Benefits

NU recorded severance benefit expenses of $0.7 million and $6.5 million associated with the partial outsourcing of information technology functions and ongoing post-merger integration for the three and nine months ended September 30, 2014, respectively, and $9.2 million for the three and nine months ended September 30, 2013.  As of September 30, 2014 and December 31, 2013, the severance accrual totaled $6.4 million and $14.7 million, respectively, and was included in Other Current Liabilities on the balance sheets.


2.

REGULATORY ACCOUNTING


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


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


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


 

As of September 30, 2014

 

As of December 31, 2013

(Millions of Dollars)

NU

 

NU

Benefit Costs

$

 1,113.2 

 

$

 1,240.2 

Derivative Liabilities

 

 427.5 

 

 

 638.0 

Income Taxes, Net

 

 623.2 

 

 

 626.2 

Storm Restoration Costs

 

 493.5 

 

 

 589.6 

Goodwill-related

 

 510.5 

 

 

 525.9 

Regulatory Tracker Mechanisms

 

 235.7 

 

 

 323.4 

Contractual Obligations - Yankee Companies

 

 124.6 

 

 

 154.2 

Buy Out Agreements for Power Contracts

 

 49.8 

 

 

 70.2 

Other Regulatory Assets

 

 109.1 

 

 

 126.8 

Total Regulatory Assets

 

 3,687.1 

 

 

 4,294.5 

Less:  Current Portion

 

 446.0 

 

 

 535.8 

Total Long-Term Regulatory Assets

$

 3,241.1 

 

$

 3,758.7 


 

 

As of September 30, 2014

 

As of December 31, 2013

 

 

 

 

 

NSTAR

 

 

 

 

 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

(Millions of Dollars)

CL&P

 

Electric

 

PSNH

 

WMECO

 

CL&P

 

Electric

 

PSNH

 

WMECO

Benefit Costs

$

 242.2 

 

$

 318.1 

 

$

 78.1 

 

$

 44.3 

 

$

 297.7 

 

$

 496.7 

 

$

 100.6 

 

$

 57.3 

Derivative Liabilities

 

 421.1 

 

 

 4.3 

 

 

 - 

 

 

 - 

 

 

 630.4 

 

 

 7.7 

 

 

 - 

 

 

 - 

Income Taxes, Net

 

 427.4 

 

 

 83.3 

 

 

 38.3 

 

 

 35.3 

 

 

 415.5 

 

 

 84.0 

 

 

 40.3 

 

 

 43.7 

Storm Restoration Costs

 

 326.0 

 

 

 106.2 

 

 

 29.3 

 

 

 32.0 

 

 

 397.8 

 

 

 109.3 

 

 

 43.7 

 

 

 38.8 

Goodwill-related

 

 - 

 

 

 438.3 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 451.5 

 

 

 - 

 

 

 - 

Regulatory Tracker Mechanisms

 

 5.2 

 

 

 76.4 

 

 

 94.7 

 

 

 23.5 

 

 

 8.0 

 

 

 169.5 

 

 

 83.3 

 

 

 32.6 

Buy Out Agreements for Power Contracts

 

 - 

 

 

 45.4 

 

 

 4.4 

 

 

 - 

 

 

 - 

 

 

 64.7 

 

 

 5.5 

 

 

 - 

Other Regulatory Assets

 

 63.6 

 

 

 54.2 

 

 

 35.9 

 

 

 13.5 

 

 

 64.6 

 

 

 55.9 

 

 

 38.1 

 

 

 16.7 

Total Regulatory Assets

 

 1,485.5 

 

 

 1,126.2 

 

 

 280.7 

 

 

 148.6 

 

 

 1,814.0 

 

 

 1,439.3 

 

 

 311.5 

 

 

 189.1 

Less:  Current Portion

 

 116.5 

 

 

 128.2 

 

 

 102.5 

 

 

 38.9 

 

 

 150.9 

 

 

 204.1 

 

 

 92.2 

 

 

 43.0 

Total Long-Term Regulatory Assets

$

 1,369.0 

 

$

 998.0 

 

$

 178.2 

 

$

 109.7 

 

$

 1,663.1 

 

$

 1,235.2 

 

$

 219.3 

 

$

 146.1 


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


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



23



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


Regulatory Costs in Other Long-Term Assets:  The Regulated companies had $64.7 million ($3.2 million for CL&P, $36 million for NSTAR Electric, and $11.2 million for WMECO) and $65.1 million ($7.3 million for CL&P, $33.4 million for NSTAR Electric, and $10.1 million for WMECO) of additional regulatory costs as of September 30, 2014 and December 31, 2013, respectively, that were included in Other Long-Term Assets on the balance sheets.  These amounts represent incurred costs for which recovery has not yet been specifically approved by the applicable regulatory agency.  However, based on regulatory policies or past precedent on similar costs, management believes it is probable that these costs will ultimately be approved and recovered from customers in rates.


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


 

As of September 30, 2014

 

As of December 31, 2013

(Millions of Dollars)

NU

 

NU

Cost of Removal

$

 439.1 

 

$

 435.1 

Regulatory Tracker Mechanisms

 

 339.9 

 

 

 151.2 

AFUDC - Transmission

 

 67.2 

 

 

 68.1 

Other Regulatory Liabilities

 

 62.7 

 

 

 52.9 

Total Regulatory Liabilities

 

 908.9 

 

 

 707.3 

Less:  Current Portion

 

 399.0 

 

 

 204.3 

Total Long-Term Regulatory Liabilities

$

 509.9 

 

$

 503.0 


 

 

As of September 30, 2014

 

As of December 31, 2013

 

 

 

 

NSTAR

 

 

 

 

 

 

 

NSTAR

 

 

 

 

(Millions of Dollars)

CL&P

 

Electric

 

PSNH

 

WMECO

 

CL&P

 

Electric

 

PSNH

 

WMECO

Cost of Removal

$

 22.5 

 

$

 260.7 

 

$

 49.2 

 

$

 - 

 

$

 29.1 

 

$

 250.0 

 

$

 49.7 

 

$

 - 

Regulatory Tracker Mechanisms

 

 196.4 

 

 

 67.3 

 

 

 25.9 

 

 

 43.9 

 

 

 95.6 

 

 

 21.9 

 

 

 21.6 

 

 

 21.1 

AFUDC - Transmission

 

 53.9 

 

 

 4.1 

 

 

 - 

 

 

 9.2 

 

 

 54.7 

 

 

 4.1 

 

 

 - 

 

 

 9.3 

Other Regulatory Liabilities

 

 10.6 

 

 

 31.6 

 

 

 4.7 

 

 

 0.7 

 

 

 8.4 

 

 

 31.1 

 

 

 1.0 

 

 

 3.4 

Total Regulatory Liabilities

 

 283.4 

 

 

 363.7 

 

 

 79.8 

 

 

 53.8 

 

 

 187.8 

 

 

 307.1 

 

 

 72.3 

 

 

 33.8 

Less:  Current Portion

 

 195.7 

 

 

 97.2 

 

 

 29.2 

 

 

 43.5 

 

 

 94.0 

 

 

 54.0 

 

 

 20.6 

 

 

 19.9 

Total Long-Term Regulatory Liabilities

$

 87.7 

 

$

 266.5 

 

$

 50.6 

 

$

 10.3 

 

$

 93.8 

 

$

 253.1 

 

$

 51.7 

 

$

 13.9 


As a result of two FERC orders issued on June 19, 2014 in the pending base ROE complaint proceedings described in Note 9E, "Commitments and Contingencies – FERC Base ROE Complaints," in the second quarter of 2014 the Company had recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact of these rulings.  As of September 30, 2014, the cumulative pre-tax reserves (excluding interest) totaled $76.1 million at NU, $42.9 million at CL&P, $15.6 million at NSTAR Electric, $5.9 million at PSNH and $11.7 million at WMECO.  As of December 31, 2013, as a result of the FERC ALJ initial decision in the third quarter of 2013, the Company had an aggregate pre-tax reserve (excluding interest) of $23.7 million at NU, $12.8 million at CL&P, $5.7 million at NSTAR Electric, $2.3 million at PSNH and $2.9 million at WMECO.  These reserves were recorded in each electric subsidiary's respective transmission regulatory tracker mechanism and as a reduction of Operating Revenues.


Effective June 1, 2014, as a result of damages awarded to the Yankee Companies for spent nuclear fuel lawsuits against the DOE described in Note 9C, "Commitments and Contingencies - Contractual Obligations - Yankee Companies," the Yankee Companies returned the DOE Phase II Damages proceeds to the member companies, including CL&P, NSTAR Electric, PSNH, and WMECO, for the benefit of their respective customers.  CL&P's refund obligation to customers of $65.4 million was recorded as an offset to the deferred storm restoration costs regulatory asset, as directed by PURA.  NSTAR Electric's, PSNH's and WMECO's refund obligation to customers of $29.1 million, $13.1 million and $18.1 million, respectively, was recorded as a regulatory liability in each electric subsidiary's respective regulatory tracker mechanisms. Refunds to customers for these DOE proceeds began in the third quarter of 2014.   




24



3.

PROPERTY, PLANT AND EQUIPMENT AND ACCUMULATED DEPRECIATION


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


 

As of September 30, 2014

 

As of December 31, 2013

(Millions of Dollars)

NU

 

NU

Distribution - Electric

$

 12,306.6 

 

$

 11,950.2 

Distribution - Natural Gas

 

 2,494.5 

 

 

 2,425.9 

Transmission

 

 6,564.2 

 

 

 6,412.5 

Generation

 

 1,168.6 

 

 

 1,152.3 

Electric and Natural Gas Utility

 

 22,533.9 

 

 

 21,940.9 

Other (1)

 

 541.7 

 

 

 508.7 

Property, Plant and Equipment, Gross

 

 23,075.6 

 

 

 22,449.6 

Less:  Accumulated Depreciation

 

 

 

 

 

 

Electric and Natural Gas Utility   

 

 (5,687.0)

 

 

 (5,387.0)

 

Other

 

 (216.3)

 

 

 (196.2)

Total Accumulated Depreciation

 

 (5,903.3)

 

 

 (5,583.2)

Property, Plant and Equipment, Net

 

 17,172.3 

 

 

 16,866.4 

Construction Work in Progress

 

 1,082.3 

 

 

 709.8 

Total Property, Plant and Equipment, Net

$

 18,254.6 

 

$

 17,576.2 


(1)

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


 

As of September 30, 2014

 

As of December 31, 2013

 

 

 

 

NSTAR

 

 

 

 

 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

(Millions of Dollars)

CL&P

 

Electric

 

PSNH

 

WMECO

 

CL&P

 

Electric

 

PSNH

 

WMECO

Distribution

$

 5,104.8 

 

$

 4,812.4 

 

$

 1,654.5 

 

$

 774.8 

 

$

 4,930.7 

 

$

 4,694.7 

 

$

 1,608.2 

 

$

 756.6 

Transmission

 

 3,125.2 

 

 

 1,824.6 

 

 

 715.8 

 

 

 851.8 

 

 

 3,071.9 

 

 

 1,772.3 

 

 

 695.7 

 

 

 826.4 

Generation

 

 - 

 

 

 - 

 

 

 1,134.7 

 

 

 33.9 

 

 

 - 

 

 

 - 

 

 

 1,131.2 

 

 

 21.1 

Property, Plant and

   Equipment, Gross

 

 8,230.0 

 

 

 6,637.0 

 

 

 3,505.0 

 

 

 1,660.5 

 

 

 8,002.6 

 

 

 6,467.0 

 

 

 3,435.1 

 

 

 1,604.1 

Less:  Accumulated Depreciation

 

 (1,908.2)

 

 

 (1,726.7)

 

 

 (1,069.4)

 

 

 (291.8)

 

 

 (1,804.1)

 

 

 (1,631.3)

 

 

 (1,021.8)

 

 

 (271.5)

Property, Plant and Equipment, Net

 

 6,321.8 

 

 

 4,910.3 

 

 

 2,435.6 

 

 

 1,368.7 

 

 

 6,198.5 

 

 

 4,835.7 

 

 

 2,413.3 

 

 

 1,332.6 

Construction Work in Progress

 

 379.0 

 

 

 301.4 

 

 

 125.0 

 

 

 63.7 

 

 

 252.8 

 

 

 208.2 

 

 

 54.3 

 

 

 48.5 

Total Property, Plant and
  Equipment, Net

$

 6,700.8 

 

$

 5,211.7 

 

$

 2,560.6 

 

$

 1,432.4 

 

$

 6,451.3 

 

$

 5,043.9 

 

$

 2,467.6 

 

$

 1,381.1 


4.

DERIVATIVE INSTRUMENTS


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


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


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




25



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


 

 

As of September 30, 2014

 

 

Commodity Supply and

 

 

 

 

Net Amount Recorded as

(Millions of Dollars)

Price Risk Management

 

Netting (1)

 

Derivative Asset/(Liability)

Current Derivative Assets:

 

 

 

 

 

 

 

 

Level 2:

 

 

 

 

 

 

 

 

 

NU (1)

$

 0.4 

 

$

 - 

 

$

 0.4 

Level 3:

 

 

 

 

 

 

 

 

 

NU (1)

 

 17.4 

 

 

 (6.8)

 

 

 10.6 

 

CL&P (1)

 

 16.4 

 

 

 (6.8)

 

 

 9.6 

 

NSTAR Electric

 

 1.0 

 

 

 - 

 

 

 1.0 

 

 

 

 

 

 

 

 

 

 

Long-Term Derivative Assets:

 

 

 

 

 

 

 

 

Level 3:     

 

 

 

 

 

 

 

 

 

NU (1)

$

 96.0 

 

$

 (20.9)

 

$

 75.1 

 

CL&P (1)

 

 95.1 

 

 

 (20.9)

 

 

 74.2 

 

NSTAR Electric

 

 0.9 

 

 

 - 

 

 

 0.9 

 

 

 

 

 

 

 

 

 

 

Current Derivative Liabilities:

 

 

 

 

 

 

 

 

Level 2:

 

 

 

 

 

 

 

 

 

NU (1)

$

 (2.4)

 

$

 0.4 

 

$

 (2.0)

Level 3:

 

 

 

 

 

 

 

 

 

NU

 

 (88.3)

 

 

 - 

 

 

 (88.3)

 

CL&P

 

 (86.8)

 

 

 - 

 

 

 (86.8)

 

NSTAR Electric

 

 (1.5)

 

 

 - 

 

 

 (1.5)

 

 

 

 

 

 

 

 

 

 

Long-Term Derivative Liabilities:

 

 

 

 

 

 

 

 

Level 3:

 

 

 

 

 

 

 

 

 

NU

$

 (420.9)

 

$

 - 

 

$

 (420.9)

 

CL&P

 

 (418.1)

 

 

 - 

 

 

 (418.1)

 

NSTAR Electric

 

 (2.8)

 

 

 - 

 

 

 (2.8)


 

 

As of December 31, 2013

 

 

Commodity Supply and

 

 

 

 

Net Amount Recorded as

(Millions of Dollars)

Price Risk Management

 

Netting (1)

 

Derivative Asset/(Liability)

Current Derivative Assets:

 

 

 

 

 

 

 

 

Level 2:

 

 

 

 

 

 

 

 

 

NU  (1)

$

 1.9 

 

$

 (0.3)

 

$

 1.6 

Level 3:

 

 

 

 

 

 

 

 

 

NU (1)

 

 18.4 

 

 

 (9.8)

 

 

 8.6 

 

CL&P (1)

 

 17.1 

 

 

 (9.8)

 

 

 7.3 

 

NSTAR Electric

 

 1.2 

 

 

 - 

 

 

 1.2 

 

 

 

 

 

 

 

 

 

 

Long-Term Derivative Assets:

 

 

 

 

 

 

 

 

Level 2:

 

 

 

 

 

 

 

 

 

NU

$

 0.2 

 

$

 - 

 

$

 0.2 

Level 3:

 

 

 

 

 

 

 

 

 

NU (1)

 

 116.2 

 

 

 (42.2)

 

 

 74.0 

 

CL&P (1)

 

 113.6 

 

 

 (42.2)

 

 

 71.4 

 

 

 

 

 

 

 

 

 

 

Current Derivative Liabilities:

 

 

 

 

 

 

 

 

Level 3:

 

 

 

 

 

 

 

 

 

NU

$

 (93.7)

 

$

 - 

 

$

 (93.7)

 

CL&P

 

 (92.2)

 

 

 - 

 

 

 (92.2)

 

NSTAR Electric

 

 (1.5)

 

 

 - 

 

 

 (1.5)

 

 

 

 

 

 

 

 

 

 

Long-Term Derivative Liabilities:

 

 

 

 

 

 

 

 

Level 3:

 

 

 

 

 

 

 

 

 

NU

$

 (624.1)

 

$

 - 

 

$

 (624.1)

 

CL&P

 

 (617.1)

 

 

 - 

 

 

 (617.1)

 

NSTAR Electric

 

 (7.0)

 

 

 - 

 

 

 (7.0)


(1)

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


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


Derivatives At Fair Value with Offsetting Regulatory Amounts

Commodity Supply and Price Risk Management:  As required by regulation, CL&P, along with UI, has capacity-related contracts with generation facilities.  CL&P has a sharing agreement with UI, with 80 percent of each contract allocated to CL&P and 20 percent allocated to UI.  The combined



26



capacity of these contracts is 787 MW.  The capacity contracts extend through 2026 and obligate both CL&P and UI to make or receive payments on a monthly basis to or from the generation facilities based on the difference between a set capacity price and the forward capacity market price received in the ISO-NE capacity markets.  In addition, CL&P has a contract to purchase 0.1 million MWh of energy per year through 2020.   


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


As of September 30, 2014 and December 31, 2013, NU had NYMEX future contracts in order to reduce variability associated with the purchase price of approximately 9.7 million and 9.1 million MMBtu of natural gas, respectively.


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


 

 

Amounts Recognized on Derivatives

 

 

For the Three Months Ended September 30,

 

For the Nine Months Ended September 30,

(Millions of Dollars)

 

2014 

 

2013 

 

2014 

 

2013 

NU

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance Sheets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Regulatory Assets and Liabilities

 

$

 (15.7)

 

$

 0.3 

 

 

$

 149.9 

 

$

 48.8 

 

Statements of Income:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Purchased Power, Fuel and Transmission

 

 

 - 

 

 

 0.2 

 

 

 

 - 

 

 

 0.9 

 


Valuation of Derivative Instruments

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


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


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


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


 

As of September 30, 2014

 

As of December 31, 2013

 

 

Range

 

Period Covered

 

 

Range

 

Period Covered

Energy Prices:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  NU

$

66 

-

68 

per MWh

 

2018 - 2020

 

$

49 

-

77 

per MWh

 

2018 - 2029

  CL&P

$

66 

-

68 

per MWh

 

2018 - 2020

 

$

56 

-

58 

per MWh

 

2018 - 2029

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Capacity Prices:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  NU

$

7.03 

-

12.98 

 per kW-Month

 

2016 - 2026

 

$

5.07 

-

11.82 

 per kW-Month

 

2017 - 2029

  CL&P

$

7.03 

-

12.98 

 per kW-Month

 

2018 - 2026

 

$

5.07 

-

10.42 

 per kW-Month

 

2017 - 2026

  NSTAR Electric

$

11.00 

-

11.10 

 per kW-Month

 

2016 - 2019

 

$

5.07 

-

7.38 

 per kW-Month

 

2017 - 2019

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward Reserve:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  NU, CL&P

$

5.80 

-

9.50 

 per kW-Month

 

2014 - 2024

 

$

3.30 

-

3.30 

 per kW-Month

 

2014 - 2024

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

REC Prices:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  NU

$

41 

-

70 

 per REC

 

2014 - 2018

 

$

36 

-

87 

 per REC

 

2014 - 2029

  NSTAR Electric

$

41 

-

70 

 per REC

 

2014 - 2018

 

$

36 

-

70 

 per REC

 

2014 - 2018


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


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




27



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


 

 

For the Three Months Ended September 30,

 

For the Nine Months Ended September 30,

 

 

2014 

 

2013 

 

2014 

 

2013 

(Millions of Dollars)

NU

 

NU

 

NU

 

NU

Derivatives, Net:

 

 

 

 

 

 

 

 

 

 

 

Fair Value as of Beginning of Period

$

 (430.9)

 

$

 (788.1)

 

$

 (635.2)

 

$

 (878.6)

Net Realized/Unrealized Gains Included in:

 

 

 

 

 

 

 

 

 

 

 

 

  Net Income

 

 - 

 

 

 1.2 

 

 

 - 

 

 

 8.3 

 

  Regulatory Assets and Liabilities

 

 (13.6)

 

 

 0.8 

 

 

 147.6 

 

 

 49.6 

Settlements

 

 21.0 

 

 

 21.3 

 

 

 64.1 

 

 

 55.9 

Fair Value as of End of Period

$

 (423.5)

 

$

 (764.8)

 

$

 (423.5)

 

$

 (764.8)


 

 

For the Three Months Ended September 30,

 

 

2014 

 

 

2013 

(Millions of Dollars)

CL&P

 

NSTAR Electric

 

 

CL&P

 

NSTAR Electric

Derivatives, Net:

 

 

 

 

 

 

 

 

 

 

 

 

Fair Value as of Beginning of Period

$

 (424.6)

 

$

 (6.3)

 

 

$

 (775.8)

 

$

 (13.1)

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

 

 (15.0)

 

 

 1.4 

 

 

 

 (1.2)

 

 

 0.5 

Settlements

 

 18.5 

 

 

 2.5 

 

 

 

 21.7 

 

 

 1.0 

Fair Value as of End of Period

$

 (421.1)

 

$

 (2.4)

 

 

$

 (755.3)

 

$

 (11.6)


 

 

For the Nine Months Ended September 30,

 

 

2014 

 

 

2013 

(Millions of Dollars)

CL&P

 

NSTAR Electric

 

 

CL&P

 

NSTAR Electric

Derivatives, Net:

 

 

 

 

 

 

 

 

 

 

 

 

Fair Value as of Beginning of Period

$

 (630.6)

 

$

 (7.3)

 

 

$

 (866.2)

 

$

 (14.9)

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

 

 149.4 

 

 

 0.9 

 

 

 

 45.1 

 

 

 0.6 

Settlements

 

 60.1 

 

 

 4.0 

 

 

 

 65.8 

 

 

 2.7 

Fair Value as of End of Period

$

 (421.1)

 

$

 (2.4)

 

 

$

 (755.3)

 

$

 (11.6)


5.

MARKETABLE SECURITIES


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


In accordance with applicable accounting guidance, the Company elected to record mutual funds designated as available-for-sale at fair value and certain other equity investments as trading securities, with the changes in fair values recorded in Other Income, Net on the statements of income.  As of September 30, 2014, the mutual funds and equity investments were classified as Level 1 in the fair value hierarchy and totaled $58.2 million and $24.4 million, respectively.  As of December 31, 2013, the mutual funds were classified as Level 1 and totaled $57.2 million.  For the three months ended September 30, 2014 and 2013, net losses of $1.9 million and net gains of $3 million, respectively, were recorded in Other Income, Net.  For the nine months ended September 30, 2014 and 2013, net gains of $1.9 million and $7.3 million, respectively, were recorded in Other Income, Net.  Dividend income is recorded in Other Income, Net on the statements of income when dividends are declared.  All other marketable securities are accounted for as available-for-sale.  


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


 

 

As of September 30, 2014

 

 

 

 

 

Pre-Tax

 

Pre-Tax

 

 

 

 

 

Amortized

 

Unrealized

 

Unrealized

 

 

 

(Millions of Dollars)

Cost

 

Gains

 

Losses

 

Fair Value

NU

 

 

 

 

 

 

 

 

 

 

 

 

Debt Securities (1)

$

 310.6 

 

$

 7.8 

 

$

 (0.2)

 

$

 318.2 

 

Equity Securities (1)

 

 160.9 

 

 

 71.1 

 

 

 - 

 

 

 232.0 

 

 

 

 

 

 

 

 

 

 

 

 

 

WMECO  

 

 

 

 

 

 

 

 

 

 

 

 

Debt Securities (2)

 

 58.1 

 

 

 0.1 

 

 

 (0.1)

 

 

 58.1 




28




 

 

As of December 31, 2013

 

 

 

 

 

Pre-Tax

 

Pre-Tax

 

 

 

 

 

Amortized

 

Unrealized

 

Unrealized

 

 

 

(Millions of Dollars)

Cost

 

Gains

 

Losses

 

Fair Value

NU

 

 

 

 

 

 

 

 

 

 

 

 

Debt Securities (1)

$

 299.2 

 

$

 2.5 

 

$

 (2.1)

 

$

 299.6 

 

Equity Securities (1)

 

 163.6 

 

 

 60.5 

 

 

 - 

 

 

 224.1 

 

 

 

 

 

 

 

 

 

 

 

 

 

WMECO  

 

 

 

 

 

 

 

 

 

 

 

 

Debt Securities (2)

 

 57.9 

 

 

 - 

 

 

 - 

 

 

 57.9 


(1)

NU's amounts include CYAPC's and YAEC's marketable securities held in nuclear decommissioning trusts of $447.7 million and $424 million as of September 30, 2014 and December 31, 2013, respectively, which are legally restricted and can only be used for the costs of decommissioning of the nuclear power plants owned by these companies. Unrealized gains and losses for the nuclear decommissioning trusts are offset in Other Long-Term Liabilities on the balance sheets, with no impact on the statements of income.  All of the equity securities accounted for as available-for-sale securities are held in the CYAPC and YAEC trusts.


(2)

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


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


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


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


 

 

NU

 

WMECO

 

 

Amortized

 

 

 

Amortized

 

 

(Millions of Dollars)

Cost

 

Fair Value

 

Cost

 

Fair Value

Less than one year (1)

$

 47.6 

 

$

 47.6 

 

$

 21.9 

 

$

 22.1 

One to five years

 

 91.0 

 

 

 91.4 

 

 

 30.7 

 

 

 30.5 

Six to ten years

 

 65.6 

 

 

 67.5 

 

 

 1.4 

 

 

 1.4 

Greater than ten years

 

 106.4 

 

 

 111.7 

 

 

 4.1 

 

 

 4.1 

Total Debt Securities

$

 310.6 

 

$

 318.2 

 

$

 58.1 

 

$

 58.1 


(1)

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


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


 

 

 

 

NU

 

WMECO

 

 

 

 

As of

 

As of

(Millions of Dollars)

September 30, 2014

 

December 31, 2013

 

September 30, 2014

 

December 31, 2013

Level 1:  

 

 

 

 

 

 

 

 

 

 

 

 

Mutual Funds and Equities

$

 314.6 

 

$

 281.3 

 

$

 - 

 

$

 - 

 

Money Market Funds

 

 27.1 

 

 

 32.9 

 

 

 4.4 

 

 

 10.9 

Total Level 1

$

 341.7 

 

$

 314.2 

 

$

 4.4 

 

$

 10.9 

Level 2:

 

 

 

 

 

 

 

 

 

 

 

 

U.S. Government Issued Debt Securities
   (Agency and Treasury)

$

 56.5 

 

$

 61.4 

 

$

 - 

 

$

 6.8 

 

Corporate Debt Securities

 

 61.2 

 

 

 53.6 

 

 

 14.1 

 

 

 15.1 

 

Asset-Backed Debt Securities

 

 37.9 

 

 

 30.4 

 

 

 14.3 

 

 

 9.0 

 

Municipal Bonds

 

 112.5 

 

 

 105.5 

 

 

 13.9 

 

 

 11.2 

 

Other Fixed Income Securities

 

 23.0 

 

 

 15.8 

 

 

 11.4 

 

 

 4.9 

Total Level 2

$

 291.1 

 

$

 266.7 

 

$

 53.7 

 

$

 47.0 

Total Marketable Securities

$

 632.8 

 

$

 580.9 

 

$

 58.1 

 

$

 57.9 


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



29




6.

SHORT-TERM AND LONG-TERM DEBT


Credit Agreements and Commercial Paper Programs:  Effective July 23, 2014, NU parent, CL&P, PSNH, WMECO, NSTAR Gas and Yankee Gas extended the expiration date of their joint $1.45 billion revolving credit facility for one additional year to September 6, 2019.  The revolving credit facility is to be used primarily to backstop NU parent's $1.45 billion commercial paper program.  The commercial paper program allows NU parent to issue commercial paper as a form of short-term debt.  As of September 30, 2014 and December 31, 2013, NU had $964.5 million and $1.01 billion, respectively, in short-term borrowings outstanding under the NU parent commercial paper program, leaving $485.5 million and $435.5 million of available borrowing capacity as of September 30, 2014 and December 31, 2013, respectively.  The weighted-average interest rate on these borrowings as of September 30, 2014 and December 31, 2013 was 0.25 percent and 0.24 percent, respectively, which is generally based on A2/P2 rated commercial paper.  As of September 30, 2014, there were intercompany loans from NU of $105.4 million to CL&P, $153.3 million to PSNH and $13.2 million to WMECO.  As of December 31, 2013, there were intercompany loans from NU of $287.3 million to CL&P and $86.5 million to PSNH.  


Effective July 23, 2014, NSTAR Electric extended the expiration date of its $450 million revolving credit facility for one additional year to September 6, 2019.  This facility serves to backstop NSTAR Electric's existing $450 million commercial paper program.  As of September 30, 2014 and December 31, 2013, NSTAR Electric had $159.5 million and $103.5 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $290.5 million and $346.5 million of available borrowing capacity as of September 30, 2014 and December 31, 2013, respectively.  The weighted-average interest rate on these borrowings as of September 30, 2014 and December 31, 2013 was 0.16 percent and 0.13 percent, respectively, which is generally based on A2/P1 rated commercial paper.


Amounts outstanding under the commercial paper programs are generally included in Notes Payable for NU and NSTAR Electric and classified in current liabilities on the balance sheets as all borrowings are outstanding for no more than 364 days at one time.  Intercompany loans from NU to CL&P, PSNH and WMECO are included in Notes Payable to NU Parent and classified in current liabilities on the balance sheets.


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


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


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


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


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


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

 

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


7.

PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS


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




30







 

 

Pension and SERP

 

Pension and SERP

 

 

For the Three Months Ended

 

For the Nine Months Ended

 

 

September 30, 2014

 

September 30, 2013

 

September 30, 2014

 

September 30, 2013

(Millions of Dollars)

NU

 

NU

 

NU

 

NU

Service Cost

$

 19.1 

 

$

 25.6 

 

$

 60.7 

 

$

 76.7 

Interest Cost

 

 56.4 

 

 

 51.7 

 

 

 169.5 

 

 

 155.0 

Expected Return on Plan Assets

 

 (77.7)

 

 

 (69.5)

 

 

 (233.1)

 

 

 (208.5)

Actuarial Loss

 

 31.7 

 

 

 52.4 

 

 

 96.5 

 

 

 158.1 

Prior Service Cost

 

 1.1 

 

 

 1.1 

 

 

 3.3 

 

 

 3.0 

Total Net Periodic Benefit Expense

$

 30.6 

 

$

 61.3 

 

$

 96.9 

 

$

 184.3 

Capitalized Pension Expense

$

 8.3 

 

$

 18.3 

 

$

 26.7 

 

$

 54.9 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

PBOP

 

PBOP

 

 

For the Three Months Ended

 

For the Nine Months Ended

 

 

September 30, 2014

 

September 30, 2013

 

September 30, 2014

 

September 30, 2013

(Millions of Dollars)

NU

 

NU

 

NU

 

NU

Service Cost

$

 3.1 

 

$

 4.2 

 

$

 9.3 

 

$

 12.6 

Interest Cost

 

 12.4 

 

 

 11.8 

 

 

 37.1 

 

 

 35.4 

Expected Return on Plan Assets

 

 (15.8)

 

 

 (13.9)

 

 

 (47.4)

 

 

 (41.6)

Actuarial Loss

 

 3.0 

 

 

 6.5 

 

 

 9.1 

 

 

 19.5 

Prior Service Credit

 

 (0.7)

 

 

 (0.5)

 

 

 (2.1)

 

 

 (1.5)

Total Net Periodic Benefit Expense

$

 2.0 

 

$

 8.1 

 

$

 6.0 

 

$

 24.4 

Capitalized PBOP Expense

$

 1.1 

 

$

 2.6 

 

$

 1.9 

 

$

 7.6 


 

 

Pension and SERP

 

 

For the Three Months Ended September 30, 2014

 

For the Three Months Ended September 30, 2013

 

 

 

 

 

NSTAR

 

 

 

 

 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

(Millions of Dollars)

CL&P

 

Electric

 

PSNH

 

WMECO

 

CL&P

 

Electric(1)

 

PSNH

 

WMECO

Service Cost

$

 5.0 

 

$

 3.0 

 

$

 2.3 

 

$

 0.8 

 

$

 6.3 

 

$

 8.3 

 

 

 3.3 

 

$

 1.2 

Interest Cost

 

 12.5 

 

 

 10.3 

 

 

 5.7 

 

 

 2.5 

 

 

 12.1 

 

 

 14.5 

 

 

 5.8 

 

 

 2.5 

Expected Return on Plan Assets

 

 (18.7)

 

 

 (15.7)

 

 

 (9.3)

 

 

 (4.4)

 

 

 (18.4)

 

 

 (21.1)

 

 

 (9.2)

 

 

 (4.3)

Actuarial Loss

 

 8.2 

 

 

 5.9 

 

 

 2.8 

 

 

 1.7 

 

 

 13.9 

 

 

 14.4 

 

 

 5.4 

 

 

 2.9 

Prior Service Cost

 

 0.4 

 

 

 - 

 

 

 0.1 

 

 

 0.1 

 

 

 0.4 

 

 

 - 

 

 

 0.1 

 

 

 0.1 

Total Net Periodic Benefit Expense

$

 7.4 

 

$

 3.5 

 

$

 1.6 

 

$

 0.7 

 

$

 14.3 

 

$

 16.1 

 

$

 5.4 

 

$

 2.4 

Intercompany Allocations

$

 6.5 

 

$

 2.9 

 

$

 1.8 

 

$

 1.2 

 

$

 11.4 

 

$

 (2.1)

 

$

 2.6 

 

$

 2.0 

Capitalized Pension Expense

$

 4.3 

 

$

 2.6 

 

$

 0.7 

 

$

 0.6 

 

$

 7.0 

 

$

 9.8 

 

$

 1.7 

 

$

 1.3 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pension and SERP

 

 

For the Nine Months Ended September 30, 2014

 

For the Nine Months Ended September 30, 2013

 

 

 

 

 

NSTAR

 

 

 

 

 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

(Millions of Dollars)

CL&P

 

Electric

 

PSNH

 

WMECO

 

CL&P

 

Electric(1)

 

PSNH

 

WMECO

Service Cost

$

 15.2 

 

$

 10.6 

 

$

 7.4 

 

$

 2.7 

 

$

 18.7 

 

$

 24.8 

 

$

 9.8 

 

$

 3.5 

Interest Cost

 

 38.1 

 

 

 31.0 

 

 

 18.0 

 

 

 7.8 

 

 

 36.3 

 

 

 43.5 

 

 

 17.8 

 

 

 7.5 

Expected Return on Plan Assets

 

 (56.7)

 

 

 (47.3)

 

 

 (28.8)

 

 

 (13.5)

 

 

 (55.4)

 

 

 (63.3)

 

 

 (26.2)

 

 

 (13.0)

Actuarial Loss

 

 25.5 

 

 

 17.6 

 

 

 8.9 

 

 

 5.2 

 

 

 42.0 

 

 

 43.6 

 

 

 16.2 

 

 

 8.9 

Prior Service Cost/(Credit)

 

 1.4 

 

 

 - 

 

 

 0.5 

 

 

 0.3 

 

 

 1.4 

 

 

 (0.2)

 

 

 0.4 

 

 

 0.3 

Total Net Periodic Benefit Expense

$

 23.5 

 

$

 11.9 

 

$

 6.0 

 

$

 2.5 

 

$

 43.0 

 

$

 48.4 

 

$

 18.0 

 

$

 7.2 

Intercompany Allocations

$

 20.8 

 

$

 6.7 

 

$

 6.0 

 

$

 3.9 

 

$

 33.6 

 

$

 (6.2)

 

$

 7.8 

 

$

 6.0 

Capitalized Pension Expense

$

 13.6 

 

$

 5.5 

 

$

 2.4 

 

$

 2.0 

 

$

 21.0 

 

$

 21.6 

 

$

 5.6 

 

$

 3.9 


 

 

PBOP

 

 

For the Three Months Ended September 30, 2014

 

For the Three Months Ended September 30, 2013

(Millions of Dollars)

CL&P

 

 

NSTAR Electric

 

 

PSNH

 

 

WMECO

 

CL&P

 

PSNH

 

WMECO

Service Cost

$

 0.6 

 

$

 0.8 

 

$

 0.3 

 

$

 0.1 

 

$

 0.9 

 

$

 0.6 

 

$

 0.2 

Interest Cost

 

 2.0 

 

 

 4.9 

 

 

 1.1 

 

 

 0.4 

 

 

 2.0 

 

 

 1.0 

 

 

 0.4 

Expected Return on Plan Assets

 

 (2.6)

 

 

 (6.5)

 

 

 (1.4)

 

 

 (0.6)

 

 

 (2.5)

 

 

 (1.3)

 

 

 (0.6)

Actuarial Loss/(Gain)

 

 1.0 

 

 

 (0.1)

 

 

 0.6 

 

 

 0.1 

 

 

 1.8 

 

 

 0.9 

 

 

 0.3 

Prior Service Credit

 

 - 

 

 

 (0.5)

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 - 

Total Net Periodic Benefit Expense/(Income)

$

 1.0 

 

$

 (1.4)

 

$

 0.6 

 

$

 0.0 

 

$

 2.2 

 

$

 1.2 

 

$

 0.3 

Intercompany Allocations

$

 0.9 

 

$

 0.3 

 

$

 0.2 

 

$

 0.2 

 

$

 1.7 

 

$

 0.4 

 

$

 0.3 

Capitalized PBOP Expense/(Income)

$

 0.5 

 

$

 (0.5)

 

$

 0.2 

 

$

 - 

 

$

 1.3 

 

$

 0.4 

 

$

 0.3 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 




31







 

 

PBOP

 

 

For the Nine Months Ended September 30, 2014

 

For the Nine Months Ended September 30, 2013

(Millions of Dollars)

CL&P

 

 

NSTAR Electric

 

 

PSNH

 

 

WMECO

 

CL&P

 

PSNH

 

WMECO

Service Cost

$

 1.7 

 

$

 2.3 

 

$

 1.0 

 

$

 0.3 

 

$

 2.6 

 

$

 1.7 

 

$

 0.5 

Interest Cost

 

 6.0 

 

 

 14.6 

 

 

 3.2 

 

 

 1.3 

 

 

 5.9 

 

 

 3.1 

 

 

 1.3 

Expected Return on Plan Assets

 

 (7.9)

 

 

 (19.5)

 

 

 (4.1)

 

 

 (1.7)

 

 

 (7.6)

 

 

 (3.9)

 

 

 (1.7)

Actuarial Loss/(Gain)

 

 3.2 

 

 

 (0.4)

 

 

 1.7 

 

 

 0.3 

 

 

 5.6 

 

 

 2.7 

 

 

 0.8 

Prior Service Credit

 

 - 

 

 

 (1.4)

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 - 

Total Net Periodic Benefit Expense/(Income)

$

 3.0 

 

$

 (4.4)

 

$

 1.8 

 

$

 0.2 

 

$

 6.5 

 

$

 3.6 

 

$

 0.9 

Intercompany Allocations

$

 3.1 

 

$

 0.4 

 

$

 0.8 

 

$

 0.6 

 

$

 5.3 

 

$

 1.2 

 

$

 1.0 

Capitalized PBOP Expense/(Income)

$

 1.5 

 

$

 (1.5)

 

$

 0.6 

 

$

 0.1 

 

$

 3.7 

 

$

 1.1 

 

$

 0.7 


(1)

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


For the three and nine months ended September 30, 2013, the net periodic PBOP expense allocated to NSTAR Electric was $1.2 million and $3.5 million, respectively.


As of December 31, 2013, the funded status of the NSTAR Pension Plan was recorded on NSTAR Electric's balance sheet while the total SERP obligation and PBOP Plan funded status were recorded on NSTAR Electric & Gas' balance sheet.  As of December 31, 2013, all NSTAR employees were employed by NSTAR Electric & Gas.  On January 1, 2014, NSTAR Electric & Gas was merged into NUSCO and, concurrently, all employees were transferred to the company they predominately provide services for: NUSCO, NSTAR Electric or NSTAR Gas.  As a result of the employee transfers, the pension and PBOP assets and liabilities were attributed by participant and transferred to the respective company's balance sheets. This change had no impact on the income statement or net assets of NSTAR Electric or NU.


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


8.

INCOME TAXES


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


9.

COMMITMENTS AND CONTINGENCIES


A.

Environmental Matters

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


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


 

As of September 30, 2014

 

 

As of December 31, 2013

 

 

 

 

Reserve

 

 

 

 

 

Reserve

 

Number of Sites

 

(in millions)

 

 

Number of Sites

 

(in millions)

NU

 

65 

 

$

 34.7 

 

 

 

 68 

 

$

 35.4 

CL&P

 

16 

 

 

 4.0 

 

 

 

 18 

 

 

 3.4 

NSTAR Electric

 

13 

 

 

 1.1 

 

 

 

 12 

 

 

 1.2 

PSNH

 

13 

 

 

 5.3 

 

 

 

 15 

 

 

 5.4 

WMECO

 

 

 

 0.5 

 

 

 

 5 

 

 

 0.4 


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




32



B.

Long-Term Contractual Arrangements

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


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


 

October - December

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Millions of Dollars)

2014 

 

2015 

 

2016 

 

2017 

 

2018 

 

Thereafter

 

Total

CL&P

$

20.0 

 

$

60.7 

 

$

66.1 

 

$

67.0 

 

$

67.7 

 

$

717.0 

 

$

998.5 

NSTAR Electric

 

21.8 

 

 

86.3 

 

 

100.0 

 

 

96.1 

 

 

59.6 

 

 

377.6 

 

 

741.4 

WMECO

 

 - 

 

 

 - 

 

 

2.4 

 

 

2.4 

 

 

2.4 

 

 

28.9 

 

 

36.1 


C.

Contractual Obligations – Yankee Companies

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


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


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


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


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


D.

Guarantees and Indemnifications

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


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


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


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


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


 

 

 

 

Maximum Exposure

 

 

 

 

Subsidiary

 

Description

 

(in millions)

 

 

Expiration Dates

Various

 

Surety Bonds

 

$

64.3 

 

 

2014 - 2016 (1)

 

 

 

 

 

 

 

 

 

 

Various

 

New England Hydro Companies' Long-Term Debt

 

$

2.0 

 

 

Unspecified

 

 

 

 

 

 

 

 

 

NUSCO and RRR

 

Lease Payments for Vehicles and Real Estate

 

$

15.3 

 

 

2019 and 2024


(1)

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


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




33



E.

FERC Base ROE Complaints

First Complaint: On September 30, 2011, a complaint was filed jointly at FERC under Sections 206 and 306 of the Federal Power Act (the "first complaint") by several New England state attorneys general, state regulatory commissions, consumer advocates and other parties (the "Complainants").  The Complainants alleged that the base ROE of 11.14 percent that has been utilized since 2006 in the calculation of formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by NETOs, including CL&P, NSTAR Electric, PSNH and WMECO, was unjust and unreasonable and asserted that the rate was excessive due to changes in the capital markets.  Complainants sought an order to reduce the base ROE prospectively from the date of a final FERC order (the "FERC order date"), and for the 15-month period October 1, 2011 to December 31, 2012 (the "first complaint refund period"), and to require refunds.  The FERC set the case for trial before a FERC ALJ after settlement negotiations were unsuccessful in August 2012.


On August 6, 2013, the FERC ALJ issued an initial decision on the first complaint finding that the base ROE in effect during the first complaint refund period was not reasonable and recommended separate base ROEs for the first complaint refund period of 10.6 percent and for the period beginning when FERC issues its final decision (the "prospective period") of 9.7 percent, leaving policy considerations and additional adjustments to the FERC.  In the third quarter of 2013, the Company recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact from the FERC ALJ's initial decision for the first complaint refund period.  See Cumulative Reserves below for further information on the reserves recorded in the third quarter of 2013.   


On June 19, 2014, FERC issued an order on the first complaint, partially affirming and partially reversing the FERC ALJ's initial decision.  FERC set a single tentative base ROE of 10.57 percent for the first complaint refund period and prospective period.  FERC also modified its traditional methodology by adopting a two-step discounted cash flow analysis that it utilizes to determine the ROEs of both natural gas and oil pipeline projects.  Using this methodology, FERC determined a new zone of reasonableness of 7.03 percent to 11.74 percent, and set the tentative base ROE halfway between the midpoint and the top of the zone of reasonableness.  FERC also stated that a utility's “total ROE, inclusive of transmission incentive ROE adders” should not exceed the top of the new zone of reasonableness produced by this methodology.  FERC instituted a paper hearing on the long-term growth rate portion of the methodology (the "paper hearing").  Rehearing requests on this new methodology were filed in July, and briefs were filed in August and September by the parties on the appropriate long-term growth rate.  In the second quarter of 2014, the Company recorded additional reserves at its electric subsidiaries to recognize the potential financial impact from the FERC’s June 19th order.  See Cumulative Reserves below for further information on the reserves recorded in the second quarter of 2014.  


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


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


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


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


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


 

 

NU

 

 

 

Third Quarter

 

 

Second Quarter

 

 

 

(Millions of Dollars)

 

2013 

 

 

2014 

 

Total

1st Complaint - Base ROE

$

 23.7 

 

$

 1.2 

 

$

 24.9 

2nd Complaint - Base ROE

 

 - 

 

 

 27.4 

 

 

 27.4 

Incentive ROE (1st and 2nd Complaint)

 

 - 

 

 

 23.8 

 

 

 23.8 

Cumulative Reserve

$

 23.7 

 

$

 52.4 

 

$

 76.1 


 

 

CL&P

 

NSTAR Electric

 

 

 

Third Quarter

 

 

Second Quarter

 

 

 

 

 

Third Quarter

 

 

Second Quarter

 

 

 

(Millions of Dollars)

 

2013 

 

 

2014 

 

Total

 

 

2013 

 

 

2014 

 

Total

1st Complaint - Base ROE

$

 12.8 

 

$

 0.5 

 

$

 13.3 

 

$

 5.7 

 

$

 0.4 

 

$

 6.1 

2nd Complaint - Base ROE

 

 - 

 

 

 13.5 

 

 

 13.5 

 

 

 - 

 

 

 7.5 

 

 

 7.5 

Incentive ROE (1st and 2nd Complaint)

 

 - 

 

 

 16.1 

 

 

 16.1 

 

 

 - 

 

 

 2.0 

 

 

 2.0 

Cumulative Reserve

$

 12.8 

 

$

 30.1 

 

$

 42.9 

 

$

 5.7 

 

$

 9.9 

 

$

 15.6 




34







 

 

PSNH

 

WMECO

 

 

 

Third Quarter

 

 

Second Quarter

 

 

 

 

 

Third Quarter

 

 

Second Quarter

 

 

 

(Millions of Dollars)

 

2013 

 

 

2014 

 

Total

 

 

2013 

 

 

2014 

 

Total

1st Complaint - Base ROE

$

 2.3 

 

$

 0.1 

 

$

 2.4 

 

$

 2.9 

 

$

 0.2 

 

$

 3.1 

2nd Complaint - Base ROE

 

 - 

 

 

 2.7 

 

 

 2.7 

 

 

 - 

 

 

 3.7 

 

 

 3.7 

Incentive ROE (1st and 2nd Complaint)

 

 - 

 

 

 0.8 

 

 

 0.8 

 

 

 - 

 

 

 4.9 

 

 

 4.9 

Cumulative Reserve

$

 2.3 

 

$

 3.6 

 

$

 5.9 

 

$

 2.9 

 

$

 8.8 

 

$

 11.7 


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


F.

CPSL

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


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


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


G.

Basic Service Bad Debt Adder

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


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


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


10.

FAIR VALUE OF FINANCIAL INSTRUMENTS


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


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


 

 

As of September 30, 2014

 

As of December 31, 2013

 

 

NU

 

NU

 

 

Carrying

 

Fair

 

Carrying

 

Fair

(Millions of Dollars)

Amount

 

Value

 

Amount

 

Value

Preferred Stock Not
  Subject to Mandatory Redemption

$

 155.6 

 

$

 151.0 

 

$

 155.6 

 

$

 152.7 

Long-Term Debt

 

 8,412.6 

 

 

 8,876.3 

 

 

 8,310.2 

 

 

 8,443.1 


 

 

As of September 30, 2014

 

 

CL&P

 

NSTAR Electric

 

PSNH

 

WMECO

 

 

Carrying

 

Fair

 

Carrying

 

Fair

 

Carrying

 

Fair

 

Carrying

 

Fair

(Millions of Dollars)

Amount

 

Value

 

Amount

 

Value

 

Amount

 

Value

 

Amount

 

Value

Preferred Stock Not
  Subject to Mandatory Redemption

$

 116.2 

 

$

 110.1 

 

$

 43.0 

 

$

 40.9 

 

$

 - 

 

$

 - 

 

$

 - 

 

$

 - 

Long-Term Debt

 

 2,841.8 

 

 

 3,189.5 

 

 

 1,797.4 

 

 

 1,959.4 

 

 

 999.2 

 

 

 1,046.4 

 

 

 628.7 

 

 

 667.4 




35







 

 

As of December 31, 2013

 

 

CL&P

 

NSTAR Electric

 

PSNH

 

WMECO

 

 

Carrying

 

Fair

 

Carrying

 

Fair

 

Carrying

 

Fair

 

Carrying

 

Fair

(Millions of Dollars)

Amount

 

Value

 

Amount

 

Value

 

Amount

 

Value

 

Amount

 

Value

Preferred Stock Not
  Subject to Mandatory Redemption

$

 116.2 

 

$

 110.5 

 

$

 43.0 

 

$

 42.2 

 

$

 - 

 

$

 - 

 

$

 - 

 

$

 - 

Long-Term Debt

 

 2,741.2 

 

 

 2,952.8 

 

 

 1,801.1 

 

 

 1,888.0 

 

 

 1,049.0 

 

 

 1,073.9 

 

 

 629.4 

 

 

 640.1 


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


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


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


11.

ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)


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


 

 

For the Nine Months Ended September 30, 2014

 

For the Nine Months Ended September 30, 2013

 

 

 

 

Unrealized

 

Pension,

 

 

 

 

 

Unrealized

 

Pension,

 

 

 

 

Qualified  

 

Gains/(Losses)

 

SERP and

 

 

 

Qualified  

 

Gains/(Losses)

 

SERP and

 

 

 

 

Cash Flow

 

on Available-

 

PBOP

 

 

 

Cash Flow

 

on Available-

 

PBOP

 

 

 

 

Hedging

 

for-Sale

 

Benefit

 

 

 

Hedging

 

for-Sale

 

Benefit

 

 

(Millions of Dollars)

Instruments

 

Securities

 

Plans

 

Total

 

Instruments

 

Securities

 

Plans

 

Total

AOCI as of Beginning of Period

 (14.4)

 

 0.4 

 

 (32.0)

 

 (46.0)

 

 (16.4)

 

 1.3 

 

 (57.8)

 

 (72.9)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

OCI Before Reclassifications

 

 - 

 

 

 0.2 

 

 

 1.2 

 

 

 1.4 

 

 

 - 

 

 

 (0.8)

 

 

 - 

 

 

 (0.8)

Amounts Reclassified from AOCI

 

 1.5 

 

 

 - 

 

 

 2.9 

 

 

 4.4 

 

 

 1.5 

 

 

 - 

 

 

 4.8 

 

 

 6.3 

   Net OCI

 

 1.5 

 

 

 0.2 

 

 

 4.1 

 

 

 5.8 

 

 

 1.5 

 

 

 (0.8)

 

 

 4.8 

 

 

 5.5 

AOCI as of End of Period

$

 (12.9)

 

$

 0.6 

 

$

 (27.9)

 

$

 (40.2)

 

$

 (14.9)

 

$

 0.5 

 

$

 (53.0)

 

$

 (67.4)


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


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


 

For the Three Months Ended

 

For the Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

Amounts Reclassified

 

Amounts Reclassified

 

Statements of Income

 

from AOCI

 

from AOCI

 

Line Item Impacted

(Millions of Dollars)

2014 

 

2013 

 

2014 

 

2013 

 

 

Qualified Cash Flow Hedging Instruments

$

(0.8)

 

$

(0.8)

 

$

(2.5)

 

$

(2.5)

 

Interest Expense

Tax Benefit

 

0.3 

 

 

0.3 

 

 

1.0 

 

 

1.0 

 

Income Tax Expense

Qualified Cash Flow Hedging Instruments, Net of Tax

$

(0.5)

 

$

(0.5)

 

$

(1.5)

 

$

(1.5)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pension, SERP and PBOP Benefit Plan Costs:

 

 

 

 

 

 

 

 

 

 

 

 

 

   Amortization of Actuarial Losses

$

(1.6)

 

$

(2.5)

 

$

(4.7)

 

$

(7.3)

 

Operations and Maintenance (1)

   Amortization of Prior Service Cost

 

 - 

 

 

 - 

 

 

 (0.1)

 

 

(0.1)

 

Operations and Maintenance (1)

Total Pension, SERP and PBOP Benefit Plan Costs

 

(1.6)

 

 

(2.5)

 

 

(4.8)

 

 

(7.4)

 

 

Tax Benefit

 

0.6 

 

 

0.9 

 

 

1.9 

 

 

2.6 

 

Income Tax Expense

Pension, SERP and PBOP Benefit Plan Costs, Net of Tax

$

(1.0)

 

$

(1.6)

 

$

(2.9)

 

$

(4.8)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Amounts Reclassified from AOCI, Net of Tax

$

(1.5)

 

$

(2.1)

 

$

(4.4)

 

$

(6.3)

 

 


(1)

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




36



12.

COMMON SHARES


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


 

Shares

 

 

 

 

Authorized as of

 

 

 

 

 

Per Share

 

September 30, 2014 and

 

Issued as of

 

Par Value

 

December 31, 2013

 

September 30, 2014

 

December 31, 2013

NU

$

 

380,000,000 

 

333,353,446 

 

333,113,492 

CL&P

$

10 

 

24,500,000 

 

 6,035,205 

 

6,035,205 

NSTAR Electric

$

 

100,000,000 

 

 100 

 

100 

PSNH

$

 

100,000,000 

 

 301 

 

301 

WMECO

$

25 

 

1,072,471 

 

 434,653 

 

434,653 


As of September 30, 2014 and December 31, 2013, there were 16,730,815 and 17,796,672 NU common shares held as treasury shares, respectively.  As of September 30, 2014 and December 31, 2013, NU common shares outstanding were 316,622,631 and 315,273,559, respectively.


13.

COMMON SHAREHOLDERS' EQUITY AND NONCONTROLLING INTERESTS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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


 

 

 

 

For the Three Months Ended

 

 

 

 

September 30, 2014

 

September 30, 2013

 

 

 

 

 

 

 

Noncontrolling

 

 

 

 

Noncontrolling

 

 

 

 

 

 

Interest -

 

 

 

 

Interest -

 

 

 

 

Common

 

Preferred

 

Common

 

Preferred

 

 

 

 

Shareholders'

 

Stock of

 

Shareholders'

 

Stock of

(Millions of Dollars)

Equity

 

Subsidiaries

 

Equity

 

Subsidiaries

Balance as of Beginning of Period

$

 9,753.8 

 

$

 155.6 

 

$

 9,406.6 

 

$

 155.6 

Net Income

 

 236.5 

 

 

 - 

 

 

 211.4 

 

 

 - 

Dividends on Common Shares

 

 (124.2)

 

 

 - 

 

 

 (114.9)

 

 

 - 

Dividends on Preferred Stock

 

 (1.9)

 

 

 (1.9)

 

 

 (1.9)

 

 

 (1.9)

Issuance of Common Shares

 

 1.0 

 

 

 - 

 

 

 1.4 

 

 

 - 

Other Transactions, Net

 

 24.1 

 

 

 - 

 

 

 12.8 

 

 

 - 

Net Income Attributable to Noncontrolling Interests

 

 - 

 

 

 1.9 

 

 

 - 

 

 

 1.9 

Other Comprehensive Income

 

 1.3 

 

 

 - 

 

 

 2.1 

 

 

 - 

Balance as of End of Period

$

 9,890.6 

 

$

 155.6 

 

$

 9,517.5 

 

$

 155.6 


 

 

 

 

For the Nine Months Ended

 

 

 

 

September 30, 2014

 

September 30, 2013

 

 

 

 

 

 

 

Noncontrolling

 

 

 

 

Noncontrolling

 

 

 

 

 

 

Interest -

 

 

 

 

Interest -

 

 

 

 

Common

 

Preferred

 

Common

 

Preferred

 

 

 

 

Shareholders'

 

Stock of

 

Shareholders'

 

Stock of

(Millions of Dollars)

Equity

 

Subsidiaries

 

Equity

 

Subsidiaries

Balance as of Beginning of Period

$

 9,611.5 

 

$

 155.6 

 

$

 9,237.1 

 

$

 155.6 

Net Income

 

 603.6 

 

 

 - 

 

 

 614.4 

 

 

 - 

Dividends on Common Shares

 

 (372.2)

 

 

 - 

 

 

 (346.9)

 

 

 - 

Dividends on Preferred Stock

 

 (5.6)

 

 

 (5.6)

 

 

 (5.8)

 

 

 (5.8)

Issuance of Common Shares

 

 6.4 

 

 

 - 

 

 

 10.2 

 

 

 - 

Other Transactions, Net

 

 41.0 

 

 

 - 

 

 

 3.0 

 

 

 - 

Net Income Attributable to Noncontrolling Interests

 

 - 

 

 

 5.6 

 

 

 - 

 

 

 5.8 

Other Comprehensive Income

 

 5.9 

 

 

 - 

 

 

 5.5 

 

 

 - 

Balance as of End of Period

$

 9,890.6 

 

$

 155.6 

 

$

 9,517.5 

 

$

 155.6 




37



14.

EARNINGS PER SHARE


Basic EPS is computed based upon the weighted average number of common shares outstanding during each period.  Diluted EPS is computed on the basis of the weighted average number of common shares outstanding plus the potential dilutive effect of certain share-based compensation awards as if they were converted into common shares.  There were no antidilutive share awards outstanding for the three and nine months ended September 30, 2014 or for the three months ended September 30, 2013.  For the nine months ended September 30, 2013, there were 2,100 antidilutive share awards excluded from the computation.


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


 

 

For the Three Months Ended

 

For the Nine Months Ended

(Millions of Dollars, except share information)

September 30, 2014

 

September 30, 2013

 

September 30, 2014

 

September 30, 2013

Net Income Attributable to Controlling Interest

$

 234.6 

 

$

 209.5 

 

$

 597.9 

 

$

 608.6 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted Average Common Shares Outstanding:

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

 316,340,691 

 

 

 315,291,346 

 

 

 315,941,904 

 

 

 315,191,752 

 

Dilutive Effect

 

 1,214,234 

 

 

 926,893 

 

 

 1,244,586 

 

 

 869,379 

 

Diluted

 

 317,554,925 

 

 

 316,218,239 

 

 

 317,186,490 

 

 

 316,061,131 

Basic and Diluted EPS

$

 0.74 

 

$

 0.66 

 

$

 1.89 

 

$

 1.93 


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


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


15.

SEGMENT INFORMATION


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


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


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


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


NU's segment information is as follows:


 

 

For the Three Months Ended September 30, 2014

 

 

Electric

 

Natural Gas

 

 

 

 

 

 

 

 

 

 

 

 

(Millions of Dollars)

Distribution

 

Distribution

 

Transmission

 

Other

 

Eliminations

 

Total

Operating Revenues

$

 1,502.6 

 

$

 109.2 

 

$

 262.5 

 

$

 211.2 

 

$

 (193.0)

 

$

 1,892.5 

Depreciation and Amortization

 

 (71.7)

 

 

 (16.4)

 

 

 (37.4)

 

 

 (13.8)

 

 

 8.6 

 

 

 (130.7)

Other Operating Expenses

 

 (1,141.5)

 

 

 (98.4)

 

 

 (74.2)

 

 

 (192.4)

 

 

 185.6 

 

 

 (1,320.9)

Operating Income/(Loss)

 

 289.4 

 

 

 (5.6)

 

 

 150.9 

 

 

 5.0 

 

 

 1.2 

 

 

 440.9 

Interest Expense

 

 (49.2)

 

 

 (8.5)

 

 

 (24.5)

 

 

 (8.6)

 

 

 1.0 

 

 

 (89.8)

Other Income, Net

 

 9.3 

 

 

 0.1 

 

 

 2.7 

 

 

 226.4 

 

 

 (226.6)

 

 

 11.9 

Net Income Attributable to Controlling Interest

$

 153.4 

 

$

 (9.9)

 

$

 88.1 

 

$

 228.3 

 

$

 (225.3)

 

$

 234.6 




38




 

 

For the Nine Months Ended September 30, 2014

 

 

Electric

 

Natural Gas

 

 

 

 

 

 

 

 

 

 

 

 

(Millions of Dollars)

Distribution

 

Distribution

 

Transmission

 

Other

 

Eliminations

 

Total

Operating Revenues

$

 4,350.4 

 

$

 737.5 

 

$

 721.4 

 

$

 568.1 

 

$

 (516.7)

 

$

 5,860.7 

Depreciation and Amortization

 

 (309.9)

 

 

 (51.1)

 

 

 (111.4)

 

 

 (28.3)

 

 

 12.7 

 

 

 (488.0)

Other Operating Expenses

 

 (3,343.9)

 

 

 (586.2)

 

 

 (211.5)

 

 

 (534.1)

 

 

 505.6 

 

 

 (4,170.1)

Operating Income

 

 696.6 

 

 

 100.2 

 

 

 398.5 

 

 

 5.7 

 

 

 1.6 

 

 

 1,202.6 

Interest Expense

 

 (143.8)

 

 

 (25.6)

 

 

 (78.8)

 

 

 (27.2)

 

 

 3.2 

 

 

 (272.2)

Other Income, Net

 

 13.6 

 

 

 0.2 

 

 

 6.9 

 

 

 657.9 

 

 

 (659.5)

 

 

 19.1 

Net Income Attributable to Controlling Interest

$

 349.1 

 

$

 44.2 

 

$

 206.8 

 

$

 653.4 

 

$

 (655.6)

 

$

 597.9 

Cash Flows Used for Investments in Plant

$

 480.1 

 

$

 120.6 

 

$

 469.9 

 

$

 46.9 

 

$

 - 

 

$

 1,117.5 


 

 

For the Three Months Ended September 30, 2013

 

 

Electric

 

Natural Gas

 

 

 

 

 

 

 

 

 

 

 

 

(Millions of Dollars)

Distribution

 

Distribution

 

Transmission

 

Other

 

Eliminations

 

Total

Operating Revenues

$

 1,508.6 

 

$

 97.1 

 

$

 234.1 

 

$

 212.5 

 

$

 (159.7)

 

$

 1,892.6 

Depreciation and Amortization

 

 (159.6)

 

 

 (16.4)

 

 

 (34.5)

 

 

 (11.2)

 

 

 2.6 

 

 

 (219.1)

Other Operating Expenses

 

 (1,064.1)

 

 

 (89.4)

 

 

 (73.4)

 

 

 (206.8)

 

 

 159.5 

 

 

 (1,274.2)

Operating Income/(Loss)

 

 284.9 

 

 

 (8.7)

 

 

 126.2 

 

 

 (5.5)

 

 

 2.4 

 

 

 399.3 

Interest Expense

 

 (44.3)

 

 

 (8.6)

 

 

 (26.6)

 

 

 (9.2)

 

 

 1.2 

 

 

 (87.5)

Other Income, Net

 

 5.5 

 

 

 0.5 

 

 

 2.9 

 

 

 312.1 

 

 

 (312.1)

 

 

 8.9 

Net Income/(Loss) Attributable to
   Controlling Interest

$

 156.9 

 

$

 (10.4)

 

$

 58.6 

 

$

 313.1 

 

$

 (308.7)

 

$

 209.5 


 

 

For the Nine Months Ended September 30, 2013

 

 

Electric

 

Natural Gas

 

 

 

 

 

 

 

 

 

 

 

 

(Millions of Dollars)

Distribution

 

Distribution

 

Transmission

 

Other

 

Eliminations

 

Total

Operating Revenues

$

 4,104.4 

 

$

 613.0 

 

$

 721.5 

 

$

 650.4 

 

$

 (565.8)

 

$

 5,523.5 

Depreciation and Amortization

 

 (488.7)

 

 

 (50.5)

 

 

 (100.9)

 

 

 (52.0)

 

 

 7.2 

 

 

 (684.9)

Other Operating Expenses

 

 (2,952.4)

 

 

 (483.6)

 

 

 (199.1)

 

 

 (599.0)

 

 

 564.3 

 

 

 (3,669.8)

Operating Income/(Loss)

 

 663.3 

 

 

 78.9 

 

 

 421.5 

 

 

 (0.6)

 

 

 5.7 

 

 

 1,168.8 

Interest Expense

 

 (129.9)

 

 

 (24.8)

 

 

 (73.7)

 

 

 (26.3)

 

 

 4.1 

 

 

 (250.6)

Other Income, Net

 

 12.6 

 

 

 0.7 

 

 

 8.5 

 

 

 866.2 

 

 

 (866.3)

 

 

 21.7 

Net Income Attributable to Controlling Interest

$

 347.5 

 

$

 34.1 

 

$

 215.4 

 

$

 868.7 

 

$

 (857.1)

 

$

 608.6 

Cash Flows Used for Investments in Plant

$

 501.9 

 

$

 91.2 

 

$

 458.2 

 

$

 22.5 

 

$

 - 

 

$

 1,073.8 


The following table summarizes NU's segmented total assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Electric

 

Natural Gas

 

 

 

 

 

 

 

 

 

 

 

 

(Millions of Dollars)

Distribution

 

Distribution

 

Transmission

 

Other

 

Eliminations

 

Total

As of September 30, 2014

$

 16,702.3 

 

$

 2,801.1 

 

$

 7,404.5 

 

$

 12,270.2 

 

$

 (11,195.8)

 

$

 27,982.3 

As of December 31, 2013

 

 17,260.0 

 

 

 2,759.7 

 

 

 6,745.8 

 

 

 11,842.4 

 

 

 (10,812.4)

 

 

 27,795.5 




39




NORTHEAST UTILITIES AND SUBSIDIARIES


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


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


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


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


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


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


·

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

·

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

·

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

·

fluctuations in weather patterns,

·

changes in laws, regulations or regulatory policy,

·

changes in levels or timing of capital expenditures,

·

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

·

developments in legal or public policy doctrines,

·

technological developments,

·

changes in accounting standards and financial reporting regulations,

·

actions of rating agencies, and

·

other presently unknown or unforeseen factors.  


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


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



40



Analysis of Financial Condition and Results of Operations and Combined Notes to Condensed Consolidated Financial Statements (Unaudited).  We encourage you to review these items.


Financial Condition and Business Analysis


Executive Summary


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


Results:


·

We earned $234.6 million, or $0.74 per share, in the third quarter of 2014 and $597.9 million, or $1.89 per share, in the first nine months of 2014, compared with $209.5 million, or $0.66 per share, in the third quarter of 2013 and $608.6 million, or $1.93 per share, in the first nine months of 2013.  Excluding integration costs, we earned $237.6 million, or $0.75 per share, in the third quarter of 2014 and $611.3 million, or $1.93 per share, in the first nine months of 2014, compared with $216.5 million, or $0.69 per share, in the third quarter of 2013, and $619.2 million, or $1.96 per share, in the first nine months of 2013.


·

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


·

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


·

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


·

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


Legislative, Regulatory and Other Items:


·

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


·

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


·

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


Liquidity:


·

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


·

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




41



·

In the first nine months of 2014, we issued $650 million of new long-term debt consisting of $100 million by Yankee Gas on January 2, 2014, $300 million by NSTAR Electric on March 7, 2014, and $250 million by CL&P on April 24, 2014.  Proceeds from these new issuances were used to repay approximately $525 million of existing long-term debt with remaining proceeds used to pay short-term borrowings.  


·

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


Overview


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


 

 

For the Three Months Ended September 30,

 

For the Nine Months Ended September 30,

(Millions of Dollars, Except

 

2014

 

2013

 

2014

 

2013

  Per Share Amounts)

 

Amount

 

Per Share

 

Amount

 

Per Share

 

Amount

 

Per Share

 

Amount

 

Per Share

Net Income Attributable to
  Controlling Interest (GAAP)

 

$

234.6 

 

$

0.74 

 

$

209.5 

 

$

 0.66 

 

$

597.9 

 

$

1.89 

 

$

608.6 

 

$

1.93 


Regulated Companies

 

$

231.6 

 

$

0.73 

 

$

205.1 

 

$

 0.65 

 

$

600.1 

 

$

1.89 

 

$

597.0 

 

$

1.89 

NU Parent and Other Companies

 

 

6.0 

 

 

0.02 

 

 

11.4 

 

 

 0.04 

 

 

11.2 

 

 

0.04 

 

 

22.2 

 

 

0.07 

Non-GAAP Earnings

 

 

237.6 

 

 

0.75 

 

 

216.5 

 

 

 0.69 

 

 

611.3 

 

 

1.93 

 

 

619.2 

 

 

1.96 

Integration Costs (after-tax)

 

 

(3.0)

 

 

(0.01)

 

 

(7.0)

 

 

 (0.03)

 

 

(13.4)

 

 

(0.04)

 

 

(10.6)

 

 

(0.03)

Net Income Attributable to
  Controlling Interest (GAAP)

 

$

234.6 

 

$

0.74 

 

$

209.5 

 

$

 0.66 

 

$

597.9 

 

$

1.89 

 

$

608.6 

 

$

1.93 


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


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


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


 

 

For the Three Months Ended September 30,

 

For the Nine Months Ended September 30,

(Millions of Dollars, Except

 

2014

 

2013

 

2014

 

2013

  Per Share Amounts)

 

Amount

 

Per Share

 

Amount

 

Per Share

 

Amount

 

Per Share

 

Amount

 

Per Share

Electric Distribution

 

$

153.4 

 

$

0.48 

 

$

156.9 

 

$

0.50 

 

$

349.1 

 

$

1.10 

 

$

347.5 

 

$

1.10 

Transmission

 

 

88.1 

 

 

0.28 

 

 

58.6 

 

 

0.18 

 

 

206.8 

 

 

0.65 

 

 

215.4 

 

 

0.68 

Natural Gas Distribution

 

 

(9.9)

 

 

(0.03)

 

 

(10.4)

 

 

(0.03)

 

 

44.2 

 

 

0.14 

 

 

34.1 

 

 

0.11 

Net Income - Regulated Companies

 

$

231.6 

 

$

0.73 

 

$

205.1 

 

$

0.65 

 

$

600.1 

 

$

1.89 

 

$

597.0 

 

$

1.89 


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


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



42




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


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


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


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


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


 

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

 

For the Nine Months Ended
September 30, 2014 Compared to 2013

 

Sales Volumes (GWh)

 

 

 

Sales Volumes (GWh)

 

Percentage

NU – Electric

2014

 

2013

 

Percentage Decrease

 

2014

 

2013

 

Increase/
(Decrease)

Residential

5,656 

 

6,102 

 

(7.3)%

 

16,306 

 

16,625 

 

(1.9)%

Commercial

7,382 

 

7,616 

 

(3.1)%

 

20,838 

 

21,064 

 

(1.1)%

Industrial

1,517 

 

1,529 

 

(0.8)%

 

4,295 

 

4,265 

 

0.7 %

Total

14,555 

 

15,247 

 

(4.5)%

 

41,439 

 

41,954 

 

(1.2)%


Percentage

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

 

For the Nine Months Ended September 30, 2014 Compared to 2013

Increase/(Decrease)
Electric

CL&P

 

NSTAR
Electric

 

PSNH

 

WMECO

 

CL&P

 

NSTAR
Electric

 

PSNH

 

WMECO

Residential

 (8.2)%

 

 (6.6)%

 

 (5.2)%

 

 (9.2)%

 

(2.0)%

 

 (2.4)%

 

 (0.3)%

 

(2.6)%

Commercial

(3.3)%

 

(2.9)%

 

(2.6)%

 

(4.3)%

 

(1.1)%

 

 (1.2)%

 

 (0.4)%

 

 (1.7)%

Industrial

 (1.3)%

 

 2.2  %

 

 (1.5)%

 

 (3.5)%

 

1.9 %

 

 (0.4)%

 

 1.5 %

 

 (3.0)%

Total

 (5.3)%

 

 (3.8)%

 

 (3.4)%

 

 (6.2)%

 

(1.2)%

 

 (1.5)%

 

 - %

 

 (2.3)%


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


 

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

 

For the Nine Months Ended
September 30, 2014 Compared to 2013

 

Sales Volumes (million cubic feet)

 

Percentage

 

Sales Volumes (million cubic feet)

 

 

NU – Firm Natural Gas

2014

 

2013

 

Increase/
(Decrease)

 

2014

 

2013

 

Percentage Increase

Residential

2,487 

 

2,407 

 

 3.3 %

 

27,468 

 

24,392 

 

 12.6%

Commercial

4,565 

 

4,673 

 

 (2.3)%

 

31,032 

 

28,066 

 

 10.6%

Industrial

4,276 

 

4,093 

 

4.4 %

 

16,669 

 

15,588 

 

6.9%

Total

11,328 

 

11,173 

 

 1.4 %

 

75,169 

 

68,046 

 

 10.5%

Total, Net of Special Contracts (1)

10,200 

 

10,155 

 

 0.4 %

 

71,645 

 

64,815 

 

 10.5%


 

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

 

For the Nine Months Ended
September 30, 2014 Compared to 2013

Percentage Increase/(Decrease)

Sales Volumes (million cubic feet)

 

Sales Volumes (million cubic feet)

Firm Natural Gas

Yankee Gas

 

NSTAR Gas

 

Yankee Gas

 

NSTAR Gas

Residential

(0.6)%

 

 6.3 %

 

14.0%

 

 11.6%

Commercial

1.7 %

 

 (6.2)%

 

14.0%

 

 7.5%

Industrial

4.6 %

 

4.0 %

 

7.3%

 

 5.9%

Total

2.8 %

 

(0.5)%

 

11.8%

 

 9.1%

Total, Net of Special Contracts (1)

1.3 %

 

 

 

12.1%

 

 


(1)

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




43



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


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


For the first nine months of 2014, our consolidated retail electric sales volumes were lower, as compared to the same period in 2013, due primarily to cooler summer weather in 2014, partially offset by colder weather in the first quarter of 2014.  The first nine months of 2014 cooling degree days were 14 percent lower in Connecticut and western Massachusetts, 16 percent lower in the Boston metropolitan area, and 24 percent lower in New Hampshire, as compared to the first nine months of 2013.  Weather-normalized retail electric sales volumes decreased 0.9 percent in the first nine months of 2014, as compared to the first nine months of 2013.  We believe the decrease was due primarily to an increase in customer conservation efforts as noted above.


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


Our firm natural gas sales are subject to many of the same influences as our retail electric sales.  In addition, they have benefitted from historically favorable natural gas prices and customer growth across both operating companies.  In the third quarter and first nine months of 2014, consolidated firm natural gas sales volumes, consisting of the firm natural gas sales volumes of Yankee Gas and NSTAR Gas, were higher, as compared to the third quarter and first nine months of 2013, due primarily to colder weather in the first quarter of 2014, as compared to the same period in 2013, and increased customer growth in the first nine months of 2014, as compared to the same period in 2013.  The third quarter and first nine months of 2014 weather-normalized NU consolidated total firm natural gas sales volumes increased 1 percent and 3.6 percent, respectively, as compared to the same periods in 2013.


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


Liquidity


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


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


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


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


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


Effective July 23, 2014, NU parent, CL&P, PSNH, WMECO, NSTAR Gas and Yankee Gas extended the expiration date of their joint $1.45 billion revolving credit facility for one additional year to September 6, 2019.  The revolving credit facility is to be used primarily to backstop NU parent's $1.45 billion commercial paper program.  The commercial paper program allows NU parent to issue commercial paper as a form of short-term debt.  As of September 30, 2014 and December 31, 2013, NU had $964.5 million and $1.01 billion, respectively, in short-term borrowings outstanding under the NU parent commercial paper program, leaving $485.5 million and $435.5 million of available borrowing capacity as of September 30, 2014 and December 31, 2013, respectively.  The weighted-average interest rate on these borrowings as of September 30, 2014 and December 31, 2013 was 0.25 percent and 0.24 percent, respectively, which is generally based on A2/P2 rated commercial paper.  As of September 30, 2014, there were intercompany loans from NU of $105.4 million to CL&P, $153.3 million to PSNH and $13.2 million to WMECO.  As of December 31, 2013, there were intercompany loans from NU of $287.3 million to CL&P and $86.5 million to PSNH.  



44




Effective July 23, 2014, NSTAR Electric extended the expiration date of its $450 million revolving credit facility for one additional year to September 6, 2019.  This facility serves to backstop NSTAR Electric's existing $450 million commercial paper program.  As of September 30, 2014 and December 31, 2013, NSTAR Electric had $159.5 million and $103.5 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $290.5 million and $346.5 million of available borrowing capacity as of September 30, 2014 and December 31, 2013, respectively.  The weighted-average interest rate on these borrowings as of September 30, 2014 and December 31, 2013 was 0.16 percent and 0.13 percent, respectively, which is generally based on A2/P1 rated commercial paper.


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


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


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


Investments in Property, Plant and Equipment on the statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension expense.  In the first nine months of 2014, investments for NU, CL&P, NSTAR Electric, PSNH, and WMECO were $1.1 billion, $371.7 million, $309.2 million, $170.1 million, and $82.5 million, respectively.  


Business Development and Capital Expenditures


Consolidated:  Our consolidated capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized portions of pension expense (all of which are non-cash factors), totaled $1.1 billion in the first nine months of both 2014 and 2013.  These amounts included $40.9 million and $14.7 million in the first nine months of 2014 and 2013, respectively, related to our corporate service companies, NUSCO and RRR.


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


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


 

 

For the Nine Months Ended September 30,

(Millions of Dollars)

 

2014

 

2013

CL&P

 

$

201.5 

 

$

133.5 

NSTAR Electric

 

 

111.1 

 

 

140.0 

PSNH

 

 

76.9 

 

 

58.0 

WMECO

 

 

50.1 

 

 

62.0 

NPT

 

 

19.4 

 

 

32.0 

Total Transmission Segment

 

$

459.0 

 

$

425.5 


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


The Interstate Reliability Project (IRP) is the second major NEEWS project.  It includes CL&P's construction of an approximately 40-mile, 345 kV overhead line from Lebanon, Connecticut to the Connecticut-Rhode Island border in Thompson, Connecticut where it will connect to transmission enhancements being constructed by National Grid in Rhode Island and Massachusetts.  As of May 2014, all three states have issued siting approvals.  The Army Corps of Engineers issued its permit on the project (the last required project permit) in the first quarter of 2014.  Project construction is underway in all three states.  NU's portion of the cost is estimated to be $218 million and construction on its portion of the project was approximately 62 percent complete as of September 30, 2014.  


The Greater Hartford Central Connecticut Study (GHCC) includes the reassessment of the Central Connecticut Reliability Project and continues to make progress.  The final need results showed existing and worsening severe regional and local thermal overloads and voltage violations within each



45



of the areas studied and across the interfaces of those areas.  These results were presented to the ISO-NE Planning Advisory Committee in November 2013.  On July 15, 2014, ISO-NE presented the preferred transmission solutions to its Planning Advisory Committee.  These solutions are comprised of many 115 kV upgrades that are expected to cost approximately $350 million and be placed in service from 2016 through 2018.  We expect to begin work on the initial solutions in late 2015 and complete GHCC-related work in 2018.


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


Through September 30, 2014, CL&P and WMECO capitalized $323.6 million and $573.6 million, respectively, in costs associated with NEEWS, of which $70.8 million and $6.6 million, respectively, were capitalized in the first nine months of 2014.  Included in the NEEWS amounts are costs for IRP, of which CL&P capitalized $140.9 million in costs through September 30, 2014, and $67.9 million related to costs capitalized in the first nine months of 2014.


Northern Pass:  Northern Pass is NU's planned HVDC transmission line from the Québec-New Hampshire border to Franklin, New Hampshire and an associated alternating current radial transmission line between Franklin and Deerfield, New Hampshire.  Northern Pass will interconnect at the Québec-New Hampshire border with a planned HQ HVDC transmission line.  NPT received ISO-NE approval under Section I.3.9 of the ISO tariff in 2013.  By approving the project's Section I.3.9 application, ISO-NE determined that Northern Pass can reliably interconnect with the New England grid with no significant adverse effect on the reliability or operating characteristics of the regional energy grid and its participants.  The DOE continues to work on the draft Environmental Impact Statement (EIS) for Northern Pass.  This includes a review of our proposed route and various alternative routes.  We now expect the DOE to issue the draft EIS in March 2015.  We expect to file the state permit application in the second quarter of 2015 after receipt of the draft EIS.  The expected $1.4 billion project is subject to comprehensive federal and state public permitting processes and is now expected to be operational in the second half of 2018.


Greater Boston Reliability Solutions: As a result of continued analysis of the transmission needs to enhance system reliability and improve capacity in eastern Massachusetts, NSTAR Electric and PSNH expect to implement a series of new transmission initiatives over the next five years.  For a portion of these new transmission initiatives, ISO-NE and state regulators must decide between two alternative transmission solutions.  We expect ISO-NE to select the preferred solution in late 2014 or early 2015.  If ISO-NE selects our solution, which is the lower overall capital cost plan, then our investments are estimated to be $489 million.  If the alternate plan is chosen, then we still expect to invest approximately $356 million.  


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


 

For the Nine Months Ended September 30,

(Millions of Dollars)

2014

 

2013

CL&P:

 

 

 

 

 

  Basic Business

$

70.2 

 

$

42.7 

  Aging Infrastructure

 

81.1 

 

 

116.6 

  Load Growth

 

49.7 

 

 

56.9 

Total CL&P

 

201.0 

 

 

216.2 

NSTAR Electric:

 

 

 

 

 

  Basic Business  

 

75.4 

 

 

84.6 

  Aging Infrastructure

 

76.0 

 

 

75.0 

  Load Growth

 

25.8 

 

 

22.5 

Total NSTAR Electric

 

177.2 

 

 

182.1 

PSNH:

 

 

 

 

 

  Basic Business

 

33.1 

 

 

13.7 

  Aging Infrastructure

 

24.2 

 

 

32.2 

  Load Growth

 

21.4 

 

 

18.3 

Total PSNH

 

78.7 

 

 

64.2 

WMECO:

 

 

 

 

 

  Basic Business

 

6.2 

 

 

5.3 

  Aging Infrastructure

 

10.2 

 

 

16.7 

  Load Growth

 

3.6 

 

 

5.7 

Total WMECO

 

20.0 

 

 

27.7 

Total - Electric Distribution (excluding Generation)

 

476.9 

 

 

490.2 

PSNH Generation

 

11.3 

 

 

5.5 

WMECO Generation

 

7.5 

 

 

0.9 

Total - Natural Gas

 

138.9 

 

 

126.7 

Total Electric and Natural Gas Distribution Segment

$

634.6 

 

$

623.3 


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




46



FERC Regulatory Issues


FERC Base ROE Complaints:

First Complaint: On September 30, 2011, a complaint was filed jointly at FERC under Sections 206 and 306 of the Federal Power Act (the "first complaint") by several New England state attorneys general, state regulatory commissions, consumer advocates and other parties (the "Complainants").  The Complainants alleged that the base ROE of 11.14 percent that has been utilized since 2006 in the calculation of formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by NETOs, including CL&P, NSTAR Electric, PSNH and WMECO, was unjust and unreasonable and asserted that the rate was excessive due to changes in the capital markets.  Complainants sought an order to reduce the base ROE prospectively from the date of a final FERC order (the "FERC order date"), and for the 15-month period October 1, 2011 to December 31, 2012 (the "first complaint refund period"), and to require refunds.  The FERC set the case for trial before a FERC ALJ after settlement negotiations were unsuccessful in August 2012.


On August 6, 2013, the FERC ALJ issued an initial decision on the first complaint finding that the base ROE in effect during the first complaint refund period was not reasonable and recommended separate base ROEs for the first complaint refund period of 10.6 percent and for the period beginning when FERC issues its final decision (the "prospective period") of 9.7 percent, leaving policy considerations and additional adjustments to the FERC.  In the third quarter of 2013, the Company recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact from the FERC ALJ's initial decision for the first complaint refund period.  See Cumulative Reserves below for further information on the reserves recorded in the third quarter of 2013.   


On June 19, 2014, FERC issued an order on the first complaint, partially affirming and partially reversing the FERC ALJ's initial decision.  FERC set a single tentative base ROE of 10.57 percent for the first complaint refund period and prospective period.  FERC also modified its traditional methodology by adopting a two-step discounted cash flow analysis that it utilizes to determine the ROEs of both natural gas and oil pipeline projects.  Using this methodology, FERC determined a new zone of reasonableness of 7.03 percent to 11.74 percent, and set the tentative base ROE halfway between the midpoint and the top of the zone of reasonableness.  FERC also stated that a utility's “total ROE, inclusive of transmission incentive ROE adders” should not exceed the top of the new zone of reasonableness produced by this methodology.  FERC instituted a paper hearing on the long-term growth rate portion of the methodology (the "paper hearing").  Rehearing requests on this new methodology were filed in July, and briefs were filed in August and September by the parties on the appropriate long-term growth rate.  In the second quarter of 2014, the Company recorded additional reserves at its electric subsidiaries to recognize the potential financial impact from the FERC’s June 19th order.  See Cumulative Reserves below for further information on the reserves recorded in the second quarter of 2014.  


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


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


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


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


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


 

 

NU

 

 

 

Third Quarter

 

 

Second Quarter

 

 

 

(Millions of Dollars)

 

2013 

 

 

2014 

 

Total

1st Complaint - Base ROE

$

 23.7 

 

$

 1.2 

 

$

 24.9 

2nd Complaint - Base ROE

 

 - 

 

 

 27.4 

 

 

 27.4 

Incentive ROE (1st and 2nd Complaint)

 

 - 

 

 

 23.8 

 

 

 23.8 

Cumulative Reserve

$

 23.7 

 

$

 52.4 

 

$

 76.1 


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




47



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


Regulatory Developments and Rate Matters


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


Connecticut:


Distribution Rates:  On June 9, 2014, CL&P filed an application with the PURA to amend customer rates, effective December 1, 2014.  The application included an increase to base distribution rates, as well as increases for the annual recovery of previously approved 2011 and 2012 deferred storm restoration costs and previously approved electric system resiliency costs.  Hearings were held in late August through the end of September 2014, followed by the legal briefing process.  After the briefing process, CL&P updated its requested increase to reflect a reduction to the storm cost recovery amounts.  The reduction primarily relates to applying the impact of the $65.4 million DOE Phase II Damages proceeds received on June 1, 2014 to the total deferred storm restoration costs of $365 million, as ordered by PURA on June 17, 2014.  A final decision is expected in December 2014.  A summary of the annual increase in distribution rates requested in the initial application and the current request is as follows:


(Millions of Dollars)

Base Distribution
Rate Increase

 

2011 and 2012

Storm Cost Recovery

 

System Resiliency

Cost Recovery

 

Total Distribution
Rate Increase

Initial Application

$

 116.7 

 

$

 89.5 

 

$

 25.3 

 

$

 231.5 

Adjustments

 

 5.7 

 

 

 (16.2)

 

 

 - 

 

 

 (10.5)

Current Request

$

 122.4 

 

$

 73.3 

 

$

 25.3 

 

$

 221.0 


Massachusetts:


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


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


New Hampshire:


Generation:  In 2013, the NHPUC opened a docket to investigate market conditions affecting PSNH's ES rate, how PSNH will maintain just and reasonable rates in light of those conditions, and any impact of PSNH's generation ownership on the New Hampshire competitive electric market.  


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


During its 2014 session, in response to the NHPUC staff report, the Legislature enacted changes to the laws governing divestiture of PSNH's generation assets, effective September 30, 2014.  The new law requires the NHPUC to initiate a proceeding before January 1, 2015, to determine whether all or some of PSNH's generation assets should be divested.  The NHPUC opened its docket DE 14-238 on September 16, 2014 and a Prehearing Conference was held on October 2, 2014.  A progress report from the NHPUC must be made by March 31, 2015.  The law also gives the NHPUC express authority to order the divestiture of all or some of PSNH's generation assets if the NHPUC finds it is in the economic interest of customers to do so.  The law also clarified the definition of "stranded costs" to include costs approved for recovery by the NHPUC in connection with the divestiture or retirement of PSNH's generation assets.  


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




48



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


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


Legislative and Policy Matters


Massachusetts:


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


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


Critical Accounting Policies


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


Other Matters


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


Contractual Obligations and Commercial Commitments:  Refer to Note 9B, "Commitments and Contingencies – Long-Term Contractual Arrangements," for discussion of material changes to contractual obligations.


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




49



RESULTS OF OPERATIONS – NORTHEAST UTILITIES AND SUBSIDIARIES


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


 

 

 

For the Three Months Ended September 30,

 

 

For the Nine Months Ended September 30,

 

 

 

 

 

 

 

 

 

 

Increase/

 

 

 

 

 

 

 

 

 

 

Increase/

 

 

 

(Millions of Dollars)

2014 

 

2013 

 

(Decrease)

 

Percent

 

 

2014 

 

2013 

 

(Decrease)

 

Percent

 

Operating Revenues

$

 1,892.5 

 

$

 1,892.6 

 

$

 (0.1)

 

 - 

%

 

$

 5,860.7 

 

$

 5,523.5 

 

$

 337.2 

 

 6.1 

%

Operating Expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Purchased Power, Fuel and Transmission

 

 716.6 

 

 

 645.9 

 

 

 70.7 

 

 10.9 

 

 

 

 2,319.0 

 

 

 1,882.0 

 

 

 437.0 

 

 23.2 

 

 

Operations and Maintenance

 

 344.1 

 

 

 386.7 

 

 

 (42.6)

 

 (11.0)

 

 

 

 1,069.0 

 

 

 1,090.0 

 

 

 (21.0)

 

 (1.9)

 

 

Depreciation

 

 153.2 

 

 

 149.1 

 

 

 4.1 

 

 2.7 

 

 

 

 456.2 

 

 

 463.6 

 

 

 (7.4)

 

 (1.6)

 

 

Amortization of Regulatory
  Assets/(Liabilities), Net

 

 (22.5)

 

 

 70.0 

 

 

 (92.5)

 

(a)

 

 

 

 31.8 

 

 

 178.7 

 

 

 (146.9)

 

 (82.2)

 

 

Amortization of Rate Reduction Bonds

 

 - 

 

 

 - 

 

 

 - 

 

 - 

 

 

 

 - 

 

 

 42.6 

 

 

 (42.6)

 

 (100.0)

 

 

Energy Efficiency Programs

 

 118.7 

 

 

 106.1 

 

 

 12.6 

 

 11.9 

 

 

 

 360.2 

 

 

 306.0 

 

 

 54.2 

 

 17.7 

 

 

Taxes Other Than Income Taxes

 

 141.5 

 

 

 135.5 

 

 

 6.0 

 

 4.4 

 

 

 

 421.9 

 

 

 391.8 

 

 

 30.1 

 

 7.7 

 

 

 

Total Operating Expenses

 

 1,451.6 

 

 

 1,493.3 

 

 

 (41.7)

 

 (2.8)

 

 

 

 4,658.1 

 

 

 4,354.7 

 

 

 303.4 

 

 7.0 

 

Operating Income

 

 440.9 

 

 

 399.3 

 

 

 41.6 

 

 10.4 

 

 

 

 1,202.6 

 

 

 1,168.8 

 

 

 33.8 

 

 2.9 

 

Interest Expense

 

 89.7 

 

 

 87.5 

 

 

 2.2 

 

 2.5 

 

 

 

 272.2 

 

 

 250.6 

 

 

 21.6 

 

 8.6 

 

Other Income, Net

 

 11.8 

 

 

 8.9 

 

 

 2.9 

 

 32.6 

 

 

 

 19.0 

 

 

 21.6 

 

 

 (2.6)

 

 (12.0)

 

Income Before Income Tax Expense

 

 363.0 

 

 

 320.7 

 

 

 42.3 

 

 13.2 

 

 

 

 949.4 

 

 

 939.8 

 

 

 9.6 

 

 1.0 

 

Income Tax Expense

 

 126.5 

 

 

 109.3 

 

 

 17.2 

 

 15.7 

 

 

 

 345.9 

 

 

 325.4 

 

 

 20.5 

 

 6.3 

 

Net Income

 

 236.5 

 

 

 211.4 

 

 

 25.1 

 

 11.9 

 

 

 

 603.5 

 

 

 614.4 

 

 

 (10.9)

 

 (1.8)

 

Net Income Attributable to Noncontrolling
  Interests

 

 1.9 

 

 

 1.9 

 

 

 - 

 

 - 

 

 

 

 5.6 

 

 

 5.8 

 

 

 (0.2)

 

 (3.4)

 

Net Income Attributable to Controlling Interest

$

 234.6 

 

$

 209.5 

 

$

 25.1 

 

 12.0 

%

 

$

 597.9 

 

$

 608.6 

 

$

 (10.7)

 

 (1.8)

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended September 30,

 

 

For the Nine Months Ended September 30,

 

 

 

 

 

 

 

 

 

 

Increase/

 

 

 

 

 

 

 

 

 

 

Increase/

 

 

 

(Millions of Dollars)

2014 

 

2013 

 

(Decrease)

 

Percent

 

 

2014 

 

2013 

 

(Decrease)

 

Percent

 

Electric Distribution

$

 1,502.6 

 

$

 1,508.6 

 

$

 (6.0)

 

 (0.4)

%

 

$

 4,350.4 

 

$

 4,104.4 

 

$

 246.0 

 

 6.0 

%

Natural Gas Distribution

 

 109.2 

 

 

 97.1 

 

 

 12.1 

 

 12.5 

 

 

 

 737.5 

 

 

 613.0 

 

 

 124.5 

 

 20.3 

 

 

Total Distribution

 

 1,611.8 

 

 

 1,605.7 

 

 

 6.1 

 

 0.4 

 

 

 

 5,087.9 

 

 

 4,717.4 

 

 

 370.5 

 

 7.9 

 

Transmission

 

 262.5 

 

 

 234.1 

 

 

 28.4 

 

 12.1 

 

 

 

 721.4 

 

 

 721.5 

 

 

 (0.1)

 

 - 

 

 

Total Regulated Companies

 

 1,874.3 

 

 

 1,839.8 

 

 

 34.5 

 

 1.9 

 

 

 

 5,809.3 

 

 

 5,438.9 

 

 

 370.4 

 

 6.8 

 

Other and Eliminations

 

 18.2 

 

 

 52.8 

 

 

 (34.6)

 

 (65.5)

 

 

 

 51.4 

 

 

 84.6 

 

 

 (33.2)

 

 (39.2)

 

Total Operating Revenues

$

 1,892.5 

 

$

 1,892.6 

 

$

 (0.1) 

 

 - 

%

 

$

 5,860.7 

 

$

 5,523.5 

 

$

 337.2 

 

 6.1 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended September 30,

 

 

For the Nine Months Ended September 30,

 

 

 

 

 

 

 

 

 

 

Increase/

 

 

 

 

 

 

 

 

 

 

Increase/

 

 

 

 

 

 

2014 

 

2013 

 

(Decrease)

 

Percent

 

 

2014 

 

2013 

 

(Decrease)

 

Percent

 

Retail Electric Sales Volumes in GWh

 

 14,555 

 

 

 15,247 

 

 

 (692)

 

 (4.5)

%

 

 

 41,439 

 

 

 41,954 

 

 

 (515)

 

 (1.2)

%

Firm Natural Gas Sales Volumes in
   Million Cubic Feet

 

 11,328 

 

 

 11,173 

 

 

 155 

 

 1.4 

 

 

 

 75,169 

 

 

 68,046 

 

 

 7,123 

 

 10.5 

 


Three Months Ended:

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


Electric base distribution revenues decreased $22.6 million compared to the same period in 2013, reflecting a 4.5 percent decrease in retail electric sales volumes.  The decrease in sales volumes reflects the cooler summer weather in 2014 as well as the impact of our utility-sponsored energy efficiency programs.  There was an increase in revenues related to the higher costs associated with purchasing electricity and natural gas on behalf of our customers.  Fluctuations in these energy supply costs are recovered from customers in rates and have no impact on earnings.  Firm natural gas sales volumes increased 1.4 percent from the third quarter of 2013 as customer growth and economic conditions in our service territory have shown steady improvement over the past year.  


As noted above, our respective utility-sponsored energy efficiency programs have the impact of reducing both retail electric and firm natural gas sales.  CL&P and NSTAR Electric bill customers for lost base revenues related to reductions in sales volume as a result of their energy efficiency.  We recognized $15.8 million of lost base revenue in the third quarter of 2014 compared to $5.5 million during the same period of 2013.


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




50



Nine Months Ended:

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


The most significant factor in the revenue increase was the overall impact of the recovery of costs associated with the procurement of energy supply.  The costs incurred to procure energy were significantly higher in 2014 than in 2013.  Our energy supply costs were impacted by higher natural gas transportation costs which, in addition to its impact on the cost of natural gas purchased on behalf of our retail natural gas customers, had an adverse impact on the cost of electric energy purchased for our retail electric customers.  Fluctuations in energy supply costs are recovered from customers in rates and have no impact on earnings.  


Firm base natural gas revenues increased $25.9 million reflecting an increase of approximately 10.5 percent in firm natural gas sales volumes.  The increase in sales volumes was driven primarily by the cold winter weather experienced throughout our service territories in the first quarter of 2014.  The winter was significantly colder than both normal and the same period last year throughout New England.  Weather-normalized total firm natural gas sales volumes (based on 30-year average temperatures) increased 3.6 percent in the first nine months of 2014, as compared to the same period in 2013, due primarily to residential and commercial customer growth.


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


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


Transmission revenues remained essentially flat in the first nine months of 2014, as compared to the first nine months of 2013, due primarily to the impact of the reserve recorded in the second quarter of 2014 as a result of the June 2014 FERC ROE orders as compared to the reserve recorded in the third quarter of 2013 for the FERC ALJ initial decision in the FERC base ROE complaints.  For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints" in this Management's Discussion and Analysis of Financial Condition and Results of Operations.


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


 

Three Months Ended

 

Nine Months Ended

(Millions of Dollars)

Increase/(Decrease)

 

Increase/(Decrease)

Electric Distribution

$

87.9 

 

$

366.0 

Natural Gas Distribution

 

10.6 

 

 

79.7 

Transmission

 

 

 

(3.2)

Other and Eliminations

 

(27.8)

 

 

(5.5)

Total Purchased Power, Fuel and Transmission

$

70.7 

 

$

437.0 


The increase in purchased power at the electric and natural gas distribution businesses were driven by the higher costs associated with the procurement of energy supply.  Our energy supply costs were impacted by higher natural gas transportation costs which, in addition to its impact on the cost of natural gas purchased on behalf of our retail natural gas customers, had an adverse impact on the cost of electric energy purchased for our retail electric customers.  




51



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


Three Months Ended

 

Nine Months Ended

(Millions of Dollars)

Increase/(Decrease)

 

Increase/(Decrease)

Base Electric Distribution:

 

 

 

 

 

   Labor and other employee-related costs, including pension costs

$

(18.8)

 

$

(62.3)

   Implementation of a new outage restoration program at CL&P

 

4.8 

 

 

9.7 

   Vegetation management costs

 

(4.7)

 

 

(0.9)

   Storm restoration costs

 

(1.6)

 

 

(10.1)

   Other operations and maintenance

 

(4.1)

 

 

21.6 

Total Base Electric Distribution

 

(24.4)

 

 

(42.0)

Total Base Natural Gas Distribution

 

(0.6)

 

 

2.3 

Total Base Electric and Natural Gas Distribution

 

(25.0)

 

 

(39.7)

Total Tracked costs (Transmission and Electric and Natural Gas Distribution)

 

(3.6)

 

 

19.9 

Total Distribution and Transmission

 

(28.6)

 

 

(19.8)

Other and eliminations:

 

 

 

 

 

  Integration and severance costs

 

(7.0)

 

 

4.5 

  All other (including eliminations)

 

(7.0)

 

 

(5.7)

Total Operations and Maintenance

$

(42.6)

 

$

(21.0)


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


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


 

Three Months Ended

 

Nine Months Ended

(Millions of Dollars)

Increase/(Decrease)

 

Increase/(Decrease)

NSTAR Electric (primarily deferred transition costs)

$

(87.8)

 

$

(174.2)

PSNH (primarily default energy service charge)

 

(10.0)

 

 

(15.9)

CL&P (primarily energy supply and energy-related costs)

 

13.1 

 

 

51.4 

WMECO (primarily deferred transition costs)

 

(7.1)

 

 

(7.2)

Other

 

(0.7)

 

 

(1.0)

Total Amortization of Regulatory Assets/(Liabilities), Net

$

(92.5)

 

$

(146.9)


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


Energy Efficiency Programs, which are tracked costs, increased for the three and nine months ended September 30, 2014, as compared to the same periods in 2013, due primarily to an increase in energy efficiency costs in accordance with the three-year program guidelines established by the DPU at NSTAR Electric and WMECO and expanded energy conservation programs at CL&P in 2014 as a result of 2013 legislative action, partially offset by a decrease in the amortization of previously deferred costs at NSTAR Electric.  


Taxes Other Than Income Taxes increased for the three and nine months ended September 30, 2014, as compared to the same periods in 2013, due primarily to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates, combined with a decrease and increase, respectively, in the Connecticut gross earnings tax for the three months and nine months ended, attributable to fluctuations in retail revenues.


Interest Expense increased for the three and nine months ended September 30, 2014, as compared to the same periods in 2013,  due primarily to the absence in 2014 of the favorable impact from the resolution of a Connecticut state income tax audit in the first quarter of 2013 ($8.8 million), lower interest income from a decrease in the recovery of previously deferred transition costs ($0.5 million and $8.2 million, respectively), and an increase in interest on long-term debt ($0.3 million and $3.9 million, respectively) as a result of new debt issuances in the first and second quarters of 2014.




52



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


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


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




53




RESULTS OF OPERATIONS – THE CONNECTICUT LIGHT AND POWER COMPANY


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


 

 

 

For the Three Months Ended September 30,

 

 

For the Nine Months Ended September 30,

 

 

 

 

 

 

 

 

 

 

Increase/

 

 

 

 

 

 

 

 

 

 

Increase/

 

 

 

(Millions of Dollars)

2014 

 

2013 

 

(Decrease)

 

Percent

 

 

2014 

 

2013 

 

(Decrease)

 

Percent

 

Operating Revenues

$

 695.6 

 

$

 648.4 

 

$

 47.2 

 

 7.3 

%

 

$

 2,017.6 

 

$

 1,841.8 

 

$

 175.8 

 

 9.5 

%

Operating Expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Purchased Power and Transmission

 

 255.8 

 

 

 253.1 

 

 

 2.7 

 

 1.1 

 

 

 

 737.0 

 

 

 667.3 

 

 

 69.7 

 

 10.4 

 

 

Operations and Maintenance

 

 127.2 

 

 

 127.1 

 

 

 0.1 

 

 0.1 

 

 

 

 368.6 

 

 

 359.7 

 

 

 8.9 

 

 2.5 

 

 

Depreciation

 

 46.9 

 

 

 44.8 

 

 

 2.1 

 

 4.7 

 

 

 

 139.6 

 

 

 132.3 

 

 

 7.3 

 

 5.5 

 

 

Amortization of Regulatory Assets, Net

 

 13.1 

 

 

 - 

 

 

 13.1 

 

 100.0 

 

 

 

 62.6 

 

 

 11.2 

 

 

 51.4 

 

(a)

 

 

Energy Efficiency Programs

 

 41.4 

 

 

 24.5 

 

 

 16.9 

 

 69.0 

 

 

 

 119.4 

 

 

 68.2 

 

 

 51.2 

 

 75.1 

 

 

Taxes Other Than Income Taxes

 

 65.0 

 

 

 65.0 

 

 

 - 

 

 - 

 

 

 

 194.1 

 

 

 182.7 

 

 

 11.4 

 

 6.2 

 

 

 

Total Operating Expenses

 

 549.4 

 

 

 514.5 

 

 

 34.9 

 

 6.8 

 

 

 

 1,621.3 

 

 

 1,421.4 

 

 

 199.9 

 

 14.1 

 

Operating Income

 

 146.2 

 

 

 133.9 

 

 

 12.3 

 

 9.2 

 

 

 

 396.3 

 

 

 420.4 

 

 

 (24.1)

 

 (5.7)

 

Interest Expense

 

 38.7 

 

 

 35.3 

 

 

 3.4 

 

 9.6 

 

 

 

 110.4 

 

 

 99.0 

 

 

 11.4 

 

 11.5 

 

Other Income, Net

 

 6.4 

 

 

 3.9 

 

 

 2.5 

 

 64.1 

 

 

 

 10.6 

 

 

 10.9 

 

 

 (0.3)

 

 (2.8)

 

Income Before Income Tax Expense

 

 113.9 

 

 

 102.5 

 

 

 11.4 

 

 11.1 

 

 

 

 296.5 

 

 

 332.3 

 

 

 (35.8)

 

 (10.8)

 

Income Tax Expense

 

 30.0 

 

 

 36.2 

 

 

 (6.2)

 

 (17.1)

 

 

 

 95.9 

 

 

 113.1 

 

 

 (17.2)

 

 (15.2)

 

Net Income

$

 83.9 

 

$

 66.3 

 

$

 17.6 

 

 26.5 

%

 

$

 200.6 

 

$

 219.2 

 

$

 (18.6)

 

 (8.5)

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended September 30,

 

 

For the Nine Months Ended September 30,

 

 

 

 

2014 

 

2013 

 

Decrease

 

Percent

 

 

2014 

 

2013 

 

Decrease

 

Percent

 

Retail Sales Volumes in GWh

 

 5,791 

 

 

 6,119 

 

 

 (328)

 

 (5.3)

%

 

 

 16,790 

 

 

 16,993 

 

 

 (203)

 

 (1.2)

%


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


CL&P's Operating Revenues increased in the first nine months of 2014, as compared to the first nine months of 2013.  The increase primarily reflects the overall impact of higher costs associated with the procurement of energy supply.  The energy supply costs were impacted by higher natural gas transportation costs, which had an adverse impact on the cost of electric energy purchased for our retail customers.  Fluctuations in energy supply costs are recovered from customers in rates and have no impact on earnings.  The increase was also driven by a higher level of recovery related to CL&P's energy efficiency programs, which has no impact on earnings, as a result of 2013 legislative action.  Partially offsetting this increase was the impact of the reserve recorded in the second quarter of 2014 as a result of the June 2014 FERC ROE orders as compared to the reserve recorded in the third quarter of 2013 for the FERC ALJ initial decision in the FERC base ROE complaints.  For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints" in this Management's Discussion and Analysis of Financial Condition and Results of Operations.


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


 

Three Months Ended

 

Nine Months Ended

(Millions of Dollars)

Increase/(Decrease)

 

Increase/(Decrease)

Purchased Power Costs

$

42.4 

 

$

111.2 

Transmission Costs

 

(34.4)

 

 

(22.6)

Other

 

(5.3)

 

 

 (18.9)

Total Purchased Power and Transmission

$

2.7 

 

$

 69.7 


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


Operations and Maintenance expense includes tracked costs and costs that are recovered through base electric distribution rates (and therefore impact earnings).  Operations and Maintenance expenses were relatively flat in the third quarter of 2014, as compared to the same period in 2013.  



54



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


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


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


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


Energy Efficiency Programs, which are tracked costs, increased for the three and nine months ended September 30, 2014, as compared to the same periods in 2013, due primarily to expanded energy conservation programs in 2014 as a result of 2013 legislative action.


Taxes Other Than Income Taxes did not materially change for the three months ended September 30, 2014 and increased for the nine months ended September 30, 2014, as compared to the same periods in 2013, due primarily to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates, and a decrease and increase, respectively, in the Connecticut gross earnings tax for the three months and nine months ended attributable to fluctuations in retail revenues.


Interest Expense increased for the three and nine months ended September 30, 2014, as compared to the same periods in 2013, due primarily to the absence in 2014 of the favorable impact from the resolution of a state income tax audit in the first quarter of 2013 ($6 million), an increase in interest on long-term debt ($1.9 million and $4.1 million, respectively) as a result of a new debt issuance in April 2014, and an increase in regulatory interest due to the refund of the DOE proceeds in the third quarter of 2014 ($1.2 million).


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


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


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


EARNINGS SUMMARY


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


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




55



LIQUIDITY


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


Investments in Property, Plant and Equipment on the statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension expense.  In the first nine months of 2014, investments for CL&P were $371.7 million.


Effective July 23, 2014, NU parent and certain of its subsidiaries, including CL&P, extended the expiration date of their joint $1.45 billion revolving credit facility for one additional year to September 6, 2019.  The revolving credit facility is to be used primarily to backstop NU parent's $1.45 billion commercial paper program.  The commercial paper program allows NU parent to issue commercial paper as a form of short-term debt to its subsidiaries, including CL&P.  As of September 30, 2014 and December 31, 2013, there were intercompany loans from NU parent of $105.4 million and $287.3 million, respectively, to CL&P.


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


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


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




56




RESULTS OF OPERATIONS – NSTAR ELECTRIC COMPANY AND SUBSIDIARY


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


 

 

 

For the Nine Months Ended September 30,

 

(Millions of Dollars)

2014 

 

2013 

 

Increase/

 

Percent

 

(Decrease)

 

Operating Revenues

$

 1,955.6 

 

$

1,916.6 

 

$

39.0 

 

2.0 

%

Operating Expenses:

 

 

 

 

 

 

 

 

 

 

 

 

Purchased Power and Transmission

 

 879.8 

 

 

659.1 

 

 

220.7 

 

33.5 

 

 

Operations and Maintenance

 

 244.6 

 

 

277.3 

 

 

(32.7)

 

(11.8)

 

 

Depreciation

 

 141.0 

 

 

136.3 

 

 

4.7 

 

3.4 

 

 

Amortization of Regulatory Assets/(Liabilities), Net

 

 (0.9)

 

 

173.3 

 

 

(174.2)

 

(a)

 

 

Amortization of Rate Reduction Bonds

 

 - 

 

 

15.1 

 

 

(15.1)

 

(100.0)

 

 

Energy Efficiency Programs

 

 145.5 

 

 

161.2 

 

 

(15.7)

 

(9.7)

 

 

Taxes Other Than Income Taxes

 

 99.1 

 

 

95.3 

 

 

3.8 

 

4.0 

 

 

 

Total Operating Expenses

 

 1,509.1 

 

 

1,517.6 

 

 

(8.5)

 

(0.6)

 

Operating Income

 

 446.5 

 

 

 399.0 

 

 

47.5 

 

11.9 

 

Interest Expense

 

 59.1 

 

 

 51.6 

 

 

7.5 

 

14.5 

 

Other Income, Net

 

 3.0 

 

 

 3.3 

 

 

(0.3)

 

(9.1)

 

Income Before Income Tax Expense

 

 390.4 

 

 

 350.7 

 

 

39.7 

 

11.3 

 

Income Tax Expense

 

 156.6 

 

 

 137.5 

 

 

19.1 

 

13.9 

 

Net Income

$

 233.8 

 

$

 213.2 

 

$

 20.6 

 

 9.7 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

 

 

 

 

 

 

 

 

 

 

 

NSTAR Electric's retail sales volumes were as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Nine Months Ended September 30,

 

 

 

 

2014 

 

2013 

 

Decrease

 

Percent

 

Retail Sales Volumes in GWh

 

 15,958 

 

 

16,204 

 

 

 (246)

 

(1.5)

%


NSTAR Electric's Operating Revenues increased in the first nine months of 2014, as compared to the first nine months of 2013.  The increase primarily reflects the overall impact of higher costs associated with the procurement of energy supply.  Our energy supply costs were impacted by higher natural gas transportation costs, which had an adverse impact on the cost of electric energy purchased for our retail customers.  Fluctuations in energy supply costs are recovered from customers in rates and have no impact on earnings.  Partially offsetting this increase was the impact of the reserve recorded in the second quarter of 2014 as a result of the June 2014 FERC ROE orders as compared to the reserve recorded in the third quarter of 2013 for the FERC ALJ initial decision in the FERC base ROE complaints.  For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints" in this Management's Discussion and Analysis of Financial Condition and Results of Operations.  Additionally, transition cost recovery revenues decreased during the period, reflecting the full collection in 2013 of previously deferred costs, as well as the full amortization of RRBs.  Base distribution revenues decreased in the first nine months of 2014, as compared to the same period in 2013, which was due primarily to cooler summer weather and customer savings due to the impact of energy efficiency programs.  NSTAR Electric is permitted to bill customers for lost base revenues related to reductions in sales volume as a result of their energy efficiency.  In the first nine months of 2014, including the impact from the recognition of lost base revenues, base distribution revenues were flat, compared to the first nine months of 2013.  


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


(Millions of Dollars)

Increase

Purchased Power Costs

$

167.6 

Transmission Costs

 

49.0 

Other

 

4.1 

Total Purchased Power and Transmission

$

220.7 


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


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


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




57



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


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


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


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


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


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


EARNINGS SUMMARY


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


LIQUIDITY


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


Effective July 23, 2014, NSTAR Electric extended the expiration date of its $450 million revolving credit facility for one additional year to September 6, 2019.  This facility serves to backstop NSTAR Electric's existing $450 million commercial paper program.  As of September 30, 2014 and December 31, 2013, NSTAR Electric had $159.5 million and $103.5 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $290.5 million and $346.5 million, respectively, of available borrowing capacity.  The weighted-average interest rate on these borrowings as of September 30, 2014 and December 31, 2013 was 0.16 percent and 0.13 percent, respectively, which is generally based on A2/P1 rated commercial paper.  




58



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


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


 

 

 

For the Nine Months Ended September 30,

 

 

 

 

 

 

 

 

 

 

Increase/

 

 

 

(Millions of Dollars)

2014 

 

2013 

 

(Decrease)

 

Percent

 

Operating Revenues

$

 735.1 

 

$

 708.6 

 

$

 26.5 

 

 3.7 

%

Operating Expenses:

 

 

 

 

 

 

 

 

 

 

 

 

Purchased Power, Fuel and Transmission

 

 248.0 

 

 

 197.8 

 

 

 50.2 

 

 25.4 

 

 

Operations and Maintenance

 

 198.0 

 

 

 191.6 

 

 

 6.4 

 

 3.3 

 

 

Depreciation

 

 73.2 

 

 

 68.4 

 

 

 4.8 

 

 7.0 

 

 

Amortization of Regulatory Assets/(Liabilities), Net

 

 (17.6)

 

 

 (1.7)

 

 

 (15.9)

 

(a)

 

 

Amortization of Rate Reduction Bonds

 

 - 

 

 

 19.7 

 

 

 (19.7)

 

 (100.0)

 

 

Energy Efficiency Programs

 

 10.9 

 

 

 11.0 

 

 

 (0.1)

 

 (0.9)

 

 

Taxes Other Than Income Taxes

 

 53.1 

 

 

 52.7 

 

 

 0.4 

 

 0.8 

 

 

 

Total Operating Expenses

 

 565.6 

 

 

 539.5 

 

 

 26.1 

 

 4.8 

 

Operating Income

 

 169.5 

 

 

 169.1 

 

 

 0.4 

 

 0.2 

 

Interest Expense

 

 34.0 

 

 

 34.2 

 

 

 (0.2)

 

 (0.6)

 

Other Income, Net

 

 1.7 

 

 

 2.4 

 

 

 (0.7)

 

 (29.2)

 

Income Before Income Tax Expense

 

 137.2 

 

 

 137.3 

 

 

 (0.1)

 

 (0.1)

 

Income Tax Expense

 

 52.2 

 

 

 52.8 

 

 

 (0.6)

 

 (1.1)

 

Net Income

$

 85.0 

 

$

 84.5 

 

$

 0.5 

 

 0.6 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

 

 

 

 

 

 

 

 

 

 

 

PSNH's retail sales volumes were as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Nine Months Ended September 30,

 

 

 

 

2014 

 

2013 

 

Decrease

 

Percent

 

Retail Sales Volumes in GWh

 

 5,970 

 

 

 5,971 

 

 

 (1)

 

-

%


PSNH's Operating Revenues increased in the first nine months of 2014, as compared to the first nine months of 2013, due primarily to the overall impact of higher costs associated with the procurement of energy supply.  The energy supply costs were impacted by higher natural gas transportation costs, which had an adverse impact on the cost of electric energy purchased for our retail customers.  Fluctuations in energy supply costs are recovered from customers in rates and therefore have no impact on earnings.  Also reflected in the revenue increase were increases of $6.7 million related to NHPUC-approved distribution rate increases effective July 1, 2013 and increases in transmission revenues as a result of the recovery of higher transmission expenses including ongoing investments in our transmission infrastructure, partially offset by the impact of the reserve recorded in the second quarter of 2014 as a result of the June 2014 FERC ROE orders as compared to the reserve recorded in the third quarter of 2013 for the FERC ALJ initial decision in the FERC base ROE complaints.  For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints" in this Management's Discussion and Analysis of Financial Condition and Results of Operations.  


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


(Millions of Dollars)

Increase/(Decrease)

Generation Fuel Costs

$

 43.0 

Transmission Costs

 

 12.3 

Purchased Power Costs

 

 (11.5)

Other

 

 6.4 

Total Purchased Power, Fuel and Transmission

$

 50.2 


The increase in generation fuel costs was due primarily to an increase in the amount of electricity generated by PSNH facilities.  The decrease in purchased power costs was a result of purchasing less power due to increased PSNH generation. The increase in transmission costs was as a result of an increase in the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers.


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


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




59



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


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


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


EARNINGS SUMMARY


For the nine months ended September 30, 2014, PSNH's earnings increased, as compared to the same period in 2013, due primarily to higher distribution retail revenues, which were favorably impacted by the PSNH annualized distribution rate increases effective July 1, 2013.  Partially offsetting this favorable earnings impact were the after-tax reserve recorded for the second quarter 2014 FERC ROE orders as compared to the reserve recorded in the third quarter 2013 for the FERC ALJ initial decision in the FERC base ROE complaints ($0.6 million increase), and higher depreciation expense.  


LIQUIDITY


PSNH had cash flows provided by operating activities of $205.8 million in the first nine months of 2014, compared with $160.4 million in the first nine months of 2013.  The improved cash flows were due primarily to $14.5 million in DOE Damages proceeds in 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, the absence of $108.3 million in Pension Plan cash contributions in the first nine months of 2014, and the favorable impact of the 2010 rate case settlement related to the additional increase to annualized rates that was effective July 1, 2013.  These favorable cash flow impacts were partially offset by changes in working capital amounts, income tax payments of $9 million in the first nine months of 2014, compared with income tax refunds of $8.7 million in the first nine months of 2013, and the absence of costs recovered in rates related to the RRBs that were fully amortized in the second quarter of 2013.




60



RESULTS OF OPERATIONS – WESTERN MASSACHUSETTS ELECTRIC COMPANY


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


 

 

 

For the Nine Months Ended September 30,

 

 

 

 

 

 

Increase/

 

 

 

(Millions of Dollars)

2014 

 

2013 

 

(Decrease)

 

Percent

 

Operating Revenues

$

 363.8 

 

$

 361.8 

 

$

 2.0 

 

 0.6 

%

Operating Expenses:

 

 

 

 

 

 

 

 

 

 

 

 

Purchased Power and Transmission

 

 131.0 

 

 

 111.1 

 

 

 19.9 

 

 17.9 

 

 

Operations and Maintenance

 

 67.1 

 

 

 70.2 

 

 

 (3.1)

 

 (4.4)

 

 

Depreciation

 

 31.1 

 

 

 27.7 

 

 

 3.4 

 

 12.3 

 

 

Amortization of Regulatory Liabilities, Net

 

 (7.8)

 

 

 (0.6)

 

 

 (7.2)

 

(a)

 

 

Amortization of Rate Reduction Bonds

 

 - 

 

 

 7.8 

 

 

 (7.8)

 

 (100.0)

 

 

Energy Efficiency Programs

 

 33.1 

 

 

 28.5 

 

 

 4.6 

 

 16.1 

 

 

Taxes Other Than Income Taxes

 

 25.7 

 

 

 20.2 

 

 

 5.5 

 

 27.2 

 

 

 

Total Operating Expenses

 

 280.2 

 

 

 264.9 

 

 

 15.3 

 

 5.8 

 

Operating Income

 

 83.6 

 

 

 96.9 

 

 

 (13.3)

 

 (13.7)

 

Interest Expense

 

 18.9 

 

 

 18.8 

 

 

 0.1 

 

 0.5 

 

Other Income, Net

 

 1.7 

 

 

 2.3 

 

 

 (0.6)

 

 (26.1)

 

Income Before Income Tax Expense

 

 66.4 

 

 

 80.4 

 

 

 (14.0)

 

 (17.4)

 

Income Tax Expense

 

 26.6 

 

 

 30.4 

 

 

 (3.8)

 

 (12.5)

 

Net Income

$

 39.8 

 

$

 50.0 

 

$

 (10.2)

 

 (20.4)

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

 

 

 

 

 

 

 

 

 

 

 

WMECO's retail sales volumes were as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Nine Months Ended September 30,

 

 

 

 

2014 

 

2013 

 

Decrease

 

Percent

 

Retail Sales Volumes in GWh

 

 2,721 

 

 

 2,786 

 

 

 (65)

 

 (2.3)

%


WMECO's Operating Revenues increased in the first nine months of 2014, as compared to the first nine months of 2013, due primarily to a higher level of recovery related to WMECO's energy supply and energy efficiency programs.  These revenues are fully reconciled to the related costs.  Therefore this increase in revenues had no material impact on earnings.  There was also a $3.9 million increase in revenues that impacts earnings due to the reversal of a previously established wholesale billing adjustment.  Partially offsetting this increase was the impact of the reserve recorded in the second quarter of 2014 as a result of the June 2014 FERC ROE orders as compared to the reserve recorded in the third quarter of 2013 for the FERC ALJ initial decision in the FERC base ROE complaints.  For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints" in this Management's Discussion and Analysis of Financial Condition and Results of Operations.  Additionally, transition cost recovery revenues decreased due to the refund to customers of proceeds received from the Yankee Companies resulting from the spent nuclear fuel litigation.  Fluctuations in WMECO's kWh sales have no impact on earnings, as its revenues are decoupled from sales volumes and changes in revenues are primarily related to changes in its cost tracking mechanisms.  


Purchased Power and Transmission expense includes costs associated with purchasing electricity on behalf of WMECO's customers.  These energy supply costs are recovered from customers in DPU-approved cost tracking mechanisms, which have no impact on earnings (tracked costs).  Purchased Power and Transmission increased for the nine months ended September 30, 2014, as compared to the same period in 2013, due primarily to an increase in purchased power due primarily to higher average supply prices and increased load as a result of customers returning to basic service from third party suppliers ($10.7 million) and an increase in transmission costs as a result of an increase in the retail transmission cost deferral ($9.2 million), which reflects the actual costs of transmission service compared to estimated amounts billed to customers.  


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


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


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


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


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




61



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


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


EARNINGS SUMMARY


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


LIQUIDITY


WMECO had cash flows provided by operating activities of $120.6 million in the first nine months of 2014, compared with $170.1 million in the first nine months of 2013.  The decrease in operating cash flows was due primarily to income tax payments of $26.5 million in the first nine months of 2014, compared with income tax payments of $16.9 million in the first nine months of 2013, changes in working capital items, and the absence of costs recovered in rates related to the RRBs that were fully amortized in the second quarter of 2013, partially offset by the receipt of $18.9 million in DOE Damages proceeds received in 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, and an increase in regulatory overrecoveries.




62




ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK


Market Risk Information


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


Other Risk Management Activities


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


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


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


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


ITEM 4.

CONTROLS AND PROCEDURES


Evaluation of Disclosure Controls and Procedures

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


Changes in Internal Control over Financial Reporting

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


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




63




PART II.  OTHER INFORMATION


ITEM 1.

LEGAL PROCEEDINGS


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


ITEM 1A.

RISK FACTORS


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


ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS


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


 

Period

 

Total Number
of Shares
Purchased

 

 

Average
Price
Paid per
Share

Total Number of
Shares Purchased
as Part of Publicly
Announced Plans or
Programs

Approximate Dollar
Value of Shares that
May Yet Be Purchased
Under the Plans and
Programs (at month end)

 

July 1 – July 31, 2014

 

-

 

$

 - 

 - 

 

August 1 – August 31, 2014

 

34,452

 

 

45.37 

 - 

 - 

 

September 1 – September 30, 2014

 

5,248

 

 

45.37 

 - 

 - 

 

Total

 

39,700

 

$

45.37 

 - 

 - 




64




ITEM 6.

EXHIBITS


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


 

Exhibit No.

 

Description

 

 

 

 

 

Listing of Exhibits (NU)

 

 

 

 

 

12

 

Ratio of Earnings to Fixed Charges

 

 

 

 

 

31

 

Certification of Thomas J. May, Chairman, President and Chief Executive Officer of NU, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 7, 2014

 

 

 

 

 

31.1

 

Certification of James J. Judge, Executive Vice President and Chief Financial Officer of NU, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 7, 2014

 

 

 

 

 

32

 

Certification of Thomas J. May, Chairman, President and Chief Executive Officer of NU, and James J. Judge, Executive Vice President and Chief Financial Officer of NU, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 7, 2014

 

 

 

 

 

Listing of Exhibits (CL&P)

 

 

 

 

*

3.1

 

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

 

 

 

 

*

4.1

 

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

 

 

 

 

 

12

 

Ratio of Earnings to Fixed Charges

 

 

 

 

 

31

 

Certification of Werner J. Schweiger, Chief Executive Officer of CL&P, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 7, 2014

 

 

 

 

 

31.1

 

Certification of James J. Judge, Executive Vice President and Chief Financial Officer of CL&P, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 7, 2014

 

 

 

 

 

32

 

Certification of Werner J. Schweiger, Chief Executive Officer of CL&P, and James J. Judge, Executive Vice President and Chief Financial Officer of CL&P, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 7, 2014

 

 

 

 

 

Listing of Exhibits (NSTAR Electric)

 

 

 

 

*

3.1

 

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

 

 

 

 

 

12

 

Ratio of Earnings to Fixed Charges

 

 

 

 

 

31

 

Certification of Werner J. Schweiger, Chief Executive Officer of NSTAR Electric, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 7, 2014

 

 

 

 

 

31.1

 

Certification of James J. Judge, Executive Vice President and Chief Financial Officer of NSTAR Electric, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 7, 2014

 

 

 

 

 

32

 

Certification of Werner J. Schweiger, Chief Executive Officer of NSTAR Electric, and James J. Judge, Executive Vice President and Chief Financial Officer of NSTAR Electric, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 7, 2014




65




 

Listing of Exhibits (PSNH)

 

 

 

 

 

3.1

 

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

 

 

 

 

*

4.1

 

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

 

 

 

 

 

12

 

Ratio of Earnings to Fixed Charges

 

 

 

 

 

31

 

Certification of Werner J. Schweiger, Chief Executive Officer of PSNH, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 7, 2014

 

 

 

 

 

31.1

 

Certification of James J. Judge, Executive Vice President and Chief Financial Officer of PSNH, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 7, 2014

 

 

 

 

 

32

 

Certification of Werner J. Schweiger, Chief Executive Officer of PSNH, and James J. Judge, Executive Vice President and Chief Financial Officer of PSNH, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 7, 2014

 

 

 

 

 

Listing of Exhibits (WMECO)

 

 

 

 

 

3.1

 

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

 

 

 

 

 

12

 

Ratio of Earnings to Fixed Charges

 

 

 

 

 

31

 

Certification of Werner J. Schweiger, Chief Executive Officer of WMECO, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 7, 2014

 

 

 

 

 

31.1

 

Certification of James J. Judge, Executive Vice President and Chief Financial Officer of WMECO, required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 7, 2014

 

 

 

 

 

32

 

Certification of Werner J. Schweiger, Chief Executive Officer of WMECO, and James J. Judge, Executive Vice President and Chief Financial Officer of WMECO, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 7, 2014


 

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

 

 

 

101.INS

 

XBRL Instance Document

 

 

 

 

 

101.SCH

 

XBRL Taxonomy Extension Schema

 

 

 

 

 

101.CAL

 

XBRL Taxonomy Extension Calculation

 

 

 

 

 

101.DEF

 

XBRL Taxonomy Extension Definition

 

 

 

 

 

101.LAB

 

XBRL Taxonomy Extension Labels

 

 

 

 

 

101.PRE

 

XBRL Taxonomy Extension Presentation

 

 

 

 




66



SIGNATURE



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



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NORTHEAST UTILITIES

 

 

 

 

November 7, 2014

 

By:

/s/

Jay S. Buth

 

 

 

Jay S. Buth

 

 

 

Vice President, Controller and Chief Accounting Officer

 

 

 


 

 

 

 



 



SIGNATURE



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



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

THE CONNECTICUT LIGHT AND POWER COMPANY

 

 

 

 

November 7, 2014

 

By:

/s/

Jay S. Buth

 

 

 

Jay S. Buth

 

 

 

Vice President, Controller and Chief Accounting Officer

 

 

 


 

 

 

 





 



SIGNATURE



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




 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NSTAR ELECTRIC COMPANY

 

 

 

 

November 7, 2014

 

By:

/s/

Jay S. Buth

 

 

 

Jay S. Buth

 

 

 

Vice President, Controller and Chief Accounting Officer

 

 

 


 

 

 

 



67



SIGNATURE



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




 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

 

 

 

 

November 7, 2014

 

By:

/s/

Jay S. Buth

 

 

 

Jay S. Buth

 

 

 

Vice President, Controller and Chief Accounting Officer

 

 

 


 

 

 

 



 



SIGNATURE



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




 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

WESTERN MASSACHUSETTS ELECTRIC COMPANY

 

 

 

 

November 7, 2014

 

By:

/s/

Jay S. Buth

 

 

 

Jay S. Buth

 

 

 

Vice President, Controller and Chief Accounting Officer

 

 

 

 

 

 

 

 











68