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EVERSOURCE ENERGY - Annual Report: 2014 (Form 10-K)

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

FORM 10-K


T

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

 

 

 

For the Fiscal Year Ended December 31, 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





 












Securities registered pursuant to Section 12(b) of the Act:



Registrant


Title of Each Class

Name of Each Exchange

   on Which Registered  

 

 

 

Northeast Utilities

Common Shares, $5.00 par value

New York Stock Exchange, Inc.

 

 

 


Securities registered pursuant to Section 12(g) of the Act:


Registrant

Title of Each Class

 

 

The Connecticut Light and Power Company

Preferred Stock, par value $50.00 per share, issuable in series, of which the following series are outstanding:



$1.90 

Series 

of 1947


$2.00 

Series

of 1947


$2.04 

Series

of 1949


$2.20 

Series

of 1949


3.90%

Series

of 1949


$2.06 

Series E

of 1954


$2.09 

Series F

of 1955


4.50% 

Series

of 1956


4.96% 

Series

of 1958


4.50% 

Series

of 1963


5.28% 

Series

of 1967


$3.24

Series G

of 1968


6.56%

Series

of 1968


NSTAR Electric Company


Preferred Stock, par value $100.00 per share, issuable in series, of which the following series are outstanding:



4.25% 

Series

 


4.78% 

Series

 


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


Indicate by check mark if the registrants are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.


 

Yes

No

 

 

 

 

T

£


Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act.


 

Yes

No

 

 

 

 

£

T


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 registrant was required to submit and post such files).


 

Yes

No

 

 

 

 

T

£






Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. £


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


The aggregate market value of Northeast Utilities' Common Shares, $5.00 par value, held by non-affiliates, computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of Northeast Utilities' most recently completed second fiscal quarter (June 30, 2014) was $14,947,688,864 based on a closing market price of $47.27 per share for the 316,219,354 common shares outstanding on June 30, 2014.  


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 January 31, 2015

Northeast Utilities
Common shares, $5.00 par value

317,203,765 shares


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


NSTAR Electric Company

Common Stock, $1.00 par value

6,035,205 shares



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.


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







GLOSSARY OF TERMS


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

 

CURRENT OR FORMER NU COMPANIES, SEGMENTS OR INVESTMENTS:

 

 

CL&P

The Connecticut Light and Power Company

CYAPC

Connecticut Yankee Atomic Power Company

MYAPC

Maine Yankee Atomic Power 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 or the Company

Northeast Utilities and subsidiaries, effective February 2, 2015, doing business as Eversource Energy

NU parent and other companies

NU parent and other companies is comprised of NU parent, NUSCO and other subsidiaries, which primarily include NU Enterprises, Inc. (the parent company of our unregulated businesses), HWP Company (formerly the Holyoke Water Power Company), The Rocky River Realty Company (a real estate subsidiary), and the consolidated operations of CYAPC and YAEC

NUSCO

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

EETV

Eversource Energy Transmission Ventures, Inc., the parent company of NPT and Renewable Properties, Inc. (formerly Northeast Utilities Transmission Ventures, 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

WMECO

Western Massachusetts Electric Company

YAEC

Yankee Atomic Electric Company

Yankee Companies

CYAPC, YAEC and MYAPC

Yankee Gas

Yankee Gas Services Company

REGULATORS:

 

DEEP

Connecticut Department of Energy and Environmental Protection

DOE

U.S. Department of Energy

DOER

Massachusetts Department of Energy Resources

DPU

Massachusetts Department of Public Utilities

EPA

U.S. Environmental Protection Agency

FERC

Federal Energy Regulatory Commission

ISO-NE

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

MA DEP

Massachusetts Department of Environmental Protection

NHPUC

New Hampshire Public Utilities Commission

PURA

Connecticut Public Utilities Regulatory Authority

SEC

U.S. Securities and Exchange Commission

SJC

Supreme Judicial Court of Massachusetts

OTHER:

 

AFUDC

Allowance For Funds Used During Construction

AOCI

Accumulated Other Comprehensive Income/(Loss)

ARO

Asset Retirement Obligation

C&LM

Conservation and Load Management

CfD

Contract for Differences

Clean Air Project

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

CO2

Carbon dioxide

CPSL

Capital Projects Scheduling List

CTA

Competitive Transition Assessment

CWIP

Construction Work in Progress

EPS

Earnings Per Share

ERISA

Employee Retirement Income Security Act of 1974

ES

Default Energy Service

ESOP

Employee Stock Ownership Plan

ESPP

Employee Share Purchase Plan

FERC ALJ

FERC Administrative Law Judge

Fitch

Fitch Ratings

FMCC

Federally Mandated Congestion Charge

FTR

Financial Transmission Rights

GAAP

Accounting principles generally accepted in the United States of America

GSC

Generation Service Charge



i





GSRP

Greater Springfield Reliability Project

GWh

Gigawatt-Hours

HQ

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

HVDC

High voltage direct current

Hydro Renewable Energy

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

IPP

Independent Power Producers

ISO-NE Tariff

ISO-NE FERC Transmission, Markets and Services Tariff

kV

Kilovolt

kW

Kilowatt (equal to one thousand watts)

kWh

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

LBR

Lost Base Revenue

LNG

Liquefied natural gas

LRS

Supplier of last resort service

MGP

Manufactured Gas Plant

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

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

2014 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS


 

Part I

Page

Item 1.

Business

2

Item 1A.

Risk Factors

15

Item 1B.

Unresolved Staff Comments

19

Item 2.

Properties

20

Item 3.

Legal Proceedings

22

Item 4.

Mine Safety Disclosures

23

 

Part II

 

Item 5.

Market for the Registrants' Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

24

Item 6.

Selected Consolidated Financial Data

26

Item 7.

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

28

Item 7A.

Quantitative and Qualitative Disclosures about Market Risk

60

Item 8.

Financial Statements and Supplementary Data

61

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

140

Item 9A.

Controls and Procedures

140

Item 9B.

Other Information

140

 

Part III

 

Item 10.

Directors, Executive Officers and Corporate Governance

141

Item 11.

Executive Compensation

144

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

169

Item 13.

Certain Relationships and Related Transactions, and Director Independence

170

Item 14.

Principal Accountant Fees and Services

171

 

Part IV

 

Item 15.

Exhibits and Financial Statement Schedules

172

Signatures

173





iii


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



SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES

LITIGATION REFORM ACT OF 1995


References in this Annual Report on Form 10-K to "NU," "the Company," "we," "our," and "us" refer to Northeast Utilities and its subsidiaries.  Effective February 2, 2015, the Company began doing business as Eversource Energy.


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


·

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

·

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

·

changes in business and economic conditions, including their impact on interest rates, bad debt expense, and demand for our products and services, which could include disruptive technology related to our current or future business model,

·

fluctuations in weather patterns,

·

changes in laws, regulations or regulatory policy,

·

changes in levels or timing of capital expenditures,

·

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

·

developments in legal or public policy doctrines,

·

technological developments,

·

changes in accounting standards and financial reporting regulations,

·

actions of rating agencies, and

·

other presently unknown or unforeseen factors.  


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


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



























































































1



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


PART I


Item 1.

Business


Please refer to the Glossary of Terms for definitions of defined terms and abbreviations used in this combined Annual Report on Form 10-K.


On February 2, 2015, NU and each of its wholly owned utility subsidiaries listed below commenced doing business as Eversource Energy.  NU, headquartered in Boston, Massachusetts and Hartford, Connecticut, is a public utility holding company subject to regulation by FERC under the Public Utility Holding Company Act of 2005.  We are engaged primarily in the energy delivery business through the following wholly owned utility subsidiaries:


·

The Connecticut Light and Power Company (CL&P), a regulated electric utility that serves residential, commercial and industrial customers in parts of Connecticut;


·

NSTAR Electric Company (NSTAR Electric), a regulated electric utility that serves residential, commercial and industrial customers in parts of Massachusetts;


·

Public Service Company of New Hampshire (PSNH), a regulated electric utility that serves residential, commercial and industrial customers in parts of New Hampshire and owns generation assets used to serve customers;


·

Western Massachusetts Electric Company (WMECO), a regulated electric utility that serves residential, commercial and industrial customers in parts of western Massachusetts and owns solar generating assets;


·

NSTAR Gas Company (NSTAR Gas), a regulated natural gas utility that serves residential, commercial and industrial customers in parts of Massachusetts; and


·

Yankee Gas Services Company (Yankee Gas), a regulated natural gas utility that serves residential, commercial and industrial customers in parts of Connecticut.


CL&P, NSTAR Electric, PSNH and WMECO also serve New England customers through NU's electric transmission business.


NU, CL&P, NSTAR Electric, PSNH and WMECO each report their financial results separately.  We also include information in this report on a segment basis for NU.  NU recognizes three reportable segments, which are electric distribution, electric transmission and natural gas distribution.  NU's electric distribution segment includes the generation businesses of PSNH and WMECO.  These three segments represented substantially all of NU's total consolidated revenues for the years ended December 31, 2014 and 2013.  CL&P, NSTAR Electric, PSNH and WMECO do not report separate business segments.   


ELECTRIC DISTRIBUTION SEGMENT


General


NU's electric distribution segment consists of the distribution businesses of CL&P, NSTAR Electric, PSNH and WMECO, which are engaged in the distribution of electricity to retail customers in Connecticut, eastern Massachusetts, New Hampshire and western Massachusetts, respectively, plus the regulated electric generation businesses of PSNH and WMECO.  


The following table shows the sources of 2014 electric franchise retail revenues for NU's electric distribution companies, collectively, based on categories of customers:


(Thousands of Dollars, except percentages)

 

2014

 

% of Total

Residential

$

3,288,313 

 

53   

Commercial

 

2,471,440 

 

40   

Industrial

 

348,698 

 

6   

Other and Eliminations

 

125,830 

 

1   

Total Retail Electric Revenues

$

6,234,281 

 

100%




2


A summary of our distribution companies' retail electric GWh sales volumes and percentage changes for 2014, as compared to 2013, is as follows:


 

2014

 

2013

 

Percentage
Change

Residential 

21,317 

 

 21,896 

 

(2.6)%

Commercial

27,449 

 

 27,787 

 

(1.2)%

Industrial 

5,676 

 

 5,648 

 

0.5 %

Total

54,442 

 

 55,331 

 

(1.6)%


Our 2014 consolidated retail electric sales volumes were lower, as compared to 2013, due primarily to cooler summer weather in 2014 as well as an increase in customer conservation efforts primarily by our residential customers, including the impact of energy efficiency programs sponsored by CL&P, NSTAR Electric and WMECO.


For WMECO and CL&P (effective December 1, 2014), fluctuations in retail electric sales volumes do not impact earnings due to the regulatory commission approved revenue decoupling mechanisms.  Distribution revenues are decoupled from their customer sales volumes.  CL&P and WMECO reconcile their annual base distribution rate recovery to pre-established levels of baseline distribution delivery service revenues.  Any difference between the allowed level of distribution revenue and the actual amount incurred during a 12-month period is adjusted through rates in the following period.  The decoupling mechanism effectively breaks the relationship between sales volumes and revenues recognized.  Prior to December 1, 2014, CL&P recognized LBR related to reductions in sales volume as a result of successful energy efficiency programs.  LBR was recovered from retail customers through the FMCC.  Effective December 1, 2014, CL&P no longer recognizes LBR due to its revenue decoupling mechanism.


ELECTRIC DISTRIBUTION – CONNECTICUT


THE CONNECTICUT LIGHT AND POWER COMPANY


CL&P's distribution business consists primarily of the purchase, delivery and sale of electricity to its residential, commercial and industrial customers.  As of December 31, 2014, CL&P furnished retail franchise electric service to approximately 1.2 million customers in 149 cities and towns in Connecticut, covering an area of 4,400 square miles. CL&P does not own any electric generation facilities.  


The following table shows the sources of CL&P's 2014 electric franchise retail revenues based on categories of customers:


 

CL&P

(Thousands of Dollars, except percentages)

 

2014

 

% of Total

Residential

$

1,474,181 

 

58   

Commercial

 

879,343 

 

35   

Industrial

 

149,220 

 

6   

Other

 

43,050 

 

1   

Total Retail Electric Revenues

$

2,545,794 

 

100%


A summary of CL&P's retail electric GWh sales volumes and percentage changes for 2014, as compared to 2013, is as follows:


 

2014

 

2013

 

Percentage
Change

Residential 

10,026 

 

 10,314 

 

(2.8)%

Commercial

9,643 

 

 9,770 

 

(1.3)%

Industrial 

2,377 

 

 2,320 

 

2.5 %

Total

22,046 

 

 22,404 

 

(1.6)%


Rates


CL&P is subject to regulation by PURA, which, among other things, has jurisdiction over rates, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service and construction and operation of facilities.  CL&P's present general rate structure consists of various rate and service classifications covering residential, commercial and industrial services.  CL&P's retail rates include a delivery service component, which includes distribution, transmission, conservation, renewables, CTA, SBC and other charges that are assessed on all customers.  Connecticut utilities are entitled under state law to charge rates that are sufficient to allow them an opportunity to recover their reasonable operating and capital costs, in order to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.


Under Connecticut law, all of CL&P's customers are entitled to choose their energy suppliers, while CL&P remains their electric distribution company.  For those customers who do not choose a competitive energy supplier, under SS rates for customers with less than 500 kilowatts of demand, and LRS rates for customers with 500 kilowatts or more of demand, CL&P purchases power under standard offer contracts and passes the cost of the power to customers through a combined GSC and FMCC charge on customers' bills.  


CL&P continues to supply approximately 45 percent of its customer load at SS or LRS rates while the other 55 percent of its customer load has migrated to competitive energy suppliers.  Because this customer migration is only for energy supply service, it has no impact on CL&P's electric distribution business or its operating income.




3


The rates established by the PURA for CL&P are comprised of the following:


·

An electric generation services charge (GSC), which 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 GSC is adjusted periodically and reconciled semi-annually in accordance with the directives of PURA.


·

A revenue decoupling adjustment (effective December 1, 2014) that reconciles the amounts recovered from customers, on an annual basis, to the distribution revenue requirement approved by the PURA in its last rate case, which currently is an annual amount of $1.041 billion.


·

A distribution charge, which includes a fixed customer charge and a demand and/or energy charge to collect the costs of building and expanding the infrastructure to deliver power to its destination, as well as ongoing operating costs to maintain the infrastructure.  


·

A federally-mandated congestion charge (FMCC), which recovers any costs imposed by the FERC as part of the New England Standard Market Design, including locational marginal pricing, locational installed capacity payments, and any costs approved by PURA to reduce these charges.  The FMCC also recovers costs associated with CL&P's system resiliency program.  The FMCC is adjusted periodically and reconciled semi-annually in accordance with the directives of PURA.


·

A transmission charge that recovers the cost of transporting electricity over high voltage lines from generating plants to substations, including costs allocated by ISO-NE to maintain the wholesale electric market.


·

A competitive transition assessment charge (CTA), assessed to recover stranded costs associated with electric industry restructuring such as various IPP contracts.  The CTA is reconciled annually to actual costs incurred and reviewed by PURA, with any difference refunded to, or recovered from, customers.


·

A systems benefits charge (SBC), established to fund expenses associated with:  various hardship and low income programs; a program to compensate municipalities for losses in property tax revenue due to decreases in the value of electric generating facilities resulting directly from electric industry restructuring; and unfunded storage and disposal costs for spent nuclear fuel generated before 1983.  The SBC is reconciled annually to actual costs incurred and reviewed by PURA, with any difference refunded to, or recovered from, customers.  


·

A Clean Energy Fund charge, which is used to promote investment in renewable energy sources.  Amounts collected by this charge are deposited into the Clean Energy Fund and administered by the Clean Energy Finance and Investment Authority.  The Clean Energy Fund charge is set by statute and is currently 0.1 cent per kWh.


·

A conservation charge, comprised of a statutory rate established to implement cost-effective energy conservation programs and market transformation initiatives, plus a conservation adjustment mechanism charge to recover the residual energy efficiency spending associated with the expanded energy efficiency costs directed by the Comprehensive Energy Strategy Plan for Connecticut.


As required by regulation, CL&P, jointly with UI, entered into the following contracts whereby UI will share 20 percent and CL&P will share 80 percent of the costs and benefits (CL&P's portion of these costs are either recovered from, or refunded to, customers through the FMCC charge):


·

Four CfDs (totaling approximately 787 MW of capacity) with three electric generation units and one demand response project, which extend through 2026 and have terms of up to 15 years beginning in 2009.  The capacity CfDs obligate both CL&P and UI to make or receive payments on a monthly basis to or from the project and generation owners based on the difference between a set capacity price and the capacity market prices that the project and generation owners receive in the ISO-NE capacity markets.


·

Three CfDs (totaling approximately 500 MW of peaking capacity) with three peaking generation units.  The three peaker CfDs pay the generation owners the difference between capacity, forward reserve and energy market revenues and a cost-of service payment stream for 30 years (including costs of plant operation and the prices that the generation owners receive for capacity and other products in the ISO-NE markets.  


·

Long-term commitments to purchase approximately 250 MW of wind power from a Maine wind farm and 20 MW of solar power from a multi-site project in Connecticut.  Both of these projects are expected to be operational by the end of 2016.


On December 17, 2014, PURA approved CL&P's application to amend customer rates, effective December 1, 2014, for a total distribution rate increase of $134 million, which includes an authorized ROE of 9.02 percent for the first twelve month period and 9.17 percent thereafter.  The distribution rate increase included a revenue decoupling reconciliation mechanism effective December 1, 2014, and the recovery of 2011 and 2012 storm restoration costs and system resiliency costs.  In addition, as part of the rate case, CL&P began recovering the 2013 storm costs and residual 2012 Storm Sandy costs over a seven-year period beginning December 1, 2014.  As of December 31, 2014, all of CL&P's deferred storm costs have been addressed by regulatory proceedings.


Sources and Availability of Electric Power Supply


As noted above, CL&P does not own any generation assets and purchases energy supply to serve its SS and LRS loads from a variety of competitive sources through requests for proposals.  CL&P periodically enters into full requirements contracts for the majority of SS loads for periods of up to one year for its residential customers and small and medium commercial and industrial customers.  CL&P is authorized to supply the remainder of the SS loads through a self-managed process that includes bilateral purchases and spot market purchases.  CL&P typically enters into full requirements contracts for LRS for larger commercial and industrial customers every three months.  Currently, CL&P has full requirements contracts



4


in place for 80 percent of its SS loads for the first half of 2015 and has bilateral purchases in place to self-manage the remaining 20 percent.  For the second half of 2015, CL&P has 50 percent of its SS load under full requirements contracts, intends to purchase an additional 20 to 30 percent of full requirements and will self-manage the remainder as needed.  None of the SS load for 2016 has been procured.  CL&P has full requirements contracts in place for its LRS loads through the second quarter of 2015 and intends to purchase 100 percent of full requirements for the third and fourth quarters of 2015.


ELECTRIC DISTRIBUTION – MASSACHUSETTS


NSTAR ELECTRIC COMPANY

WESTERN MASSACHUSETTS ELECTRIC COMPANY


The electric distribution businesses of NSTAR Electric and WMECO consist primarily of the purchase, delivery and sale of electricity to residential, commercial and industrial customers within their respective franchise service territories.  As of December 31, 2014, NSTAR Electric furnished retail franchise electric service to approximately 1.2 million customers in Boston and 80 surrounding cities and towns in Massachusetts, including Cape Cod and Martha's Vineyard, covering an area of approximately 1,700 square miles.  WMECO provides retail franchise electric service to approximately 208,000 customers in 59 cities and towns in the western region of Massachusetts, covering an area of approximately 1,500 square miles.  Neither NSTAR Electric nor WMECO owns any coal-fired, oil-fired, or hydro-electric generating facilities, and each purchases its respective energy requirements from competitive energy suppliers.  


In 2009, WMECO was authorized by the DPU to install solar energy generation in its service territory.  From 2010 through 2014, WMECO completed development of a total of 8 MW solar generation facilities on sites in Pittsfield, Springfield, and East Springfield, Massachusetts.  WMECO will sell all energy and other products from its solar generation facilities into the ISO-NE market.  NSTAR Electric does not own any solar generation facilities.


The following table shows the sources of the 2014 electric franchise retail revenues of NSTAR Electric and WMECO based on categories of customers:


 

 

NSTAR Electric

 

WMECO

(Thousands of Dollars, except percentages)

 

2014

 

% of Total

 

2014

 

% of Total

Residential

$

1,101,704 

 

46

 

$

233,675 

 

56  

Commercial

 

1,161,466 

 

49

 

 

131,093 

 

31  

Industrial

 

89,643 

 

4

 

 

37,211 

 

9  

Other

 

29,765 

 

1

 

 

15,470 

 

4  

Total Retail Electric Revenues

$

2,382,578 

 

100%

 

$

417,449 

 

100%


A summary of NSTAR Electric's and WMECO's retail electric GWh sales volumes and percentage changes for 2014, as compared to 2013, is as follows:


 

 

NSTAR Electric

 

WMECO

 

 

2014

 

2013

 

Percentage
Change

 

2014

 

2013

 

Percentage
Change

Residential 

 

6,625 

 

 6,831 

 

(3.0)%

 

1,494 

 

 1,544

 

(3.2)%

Commercial

 

13,009 

 

 13,163 

 

(1.2)%

 

1,466 

 

 1,496

 

(2.0)%

Industrial 

 

1,291 

 

 1,312 

 

(1.6)%

 

626 

 

 643

 

(2.5)%

Total

 

20,925 

 

 21,306 

 

(1.8)%

 

3,586 

 

 3,683

 

(2.6)%


Rates


NSTAR Electric and WMECO are each subject to regulation by the DPU, which, among other things, has jurisdiction over rates, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, acquisition of securities, standards of service and construction and operation of facilities.  The present general rate structure for both NSTAR Electric and WMECO consists of various rate and service classifications covering residential, commercial and industrial services.  Massachusetts utilities are entitled under state law to charge rates that are sufficient to allow them an opportunity to recover their reasonable operating and capital costs, in order to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.


Under Massachusetts law, all customers of each of NSTAR Electric and WMECO are entitled to choose their energy suppliers, while NSTAR Electric or WMECO remains their electric distribution company.  Both NSTAR Electric and WMECO purchase power from competitive suppliers on behalf of, and pass the related cost through to, their respective customers who do not choose a competitive energy supplier (basic service).  Most of the residential and small commercial and industrial customers of NSTAR Electric and WMECO have continued to buy their power from NSTAR Electric or WMECO at basic service rates.  Most large commercial and industrial customers have switched to a competitive energy supplier.  


The Cape Light Compact, an inter-governmental organization consisting of the 21 towns and two counties on Cape Cod and Martha's Vineyard, serves 200,000 customers through the delivery of energy efficiency programs, effective consumer advocacy, competitive electricity supply and green power options.  NSTAR Electric continues to provide electric service to these customers including the delivery of power, maintenance of infrastructure, capital investment, meter reading, billing, and customer service.


NSTAR Electric continues to supply approximately 44 percent of its customer load at basic service rates while the other 56 percent of its customer load has migrated to competitive energy suppliers.  WMECO continues to supply approximately 51 percent of its customer load at basic service rates



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while the other 49 percent of its customer load has migrated to competitive energy suppliers.  Because customer migration is limited to energy supply service, it has no impact on the delivery business or operating income of NSTAR and WMECO.


The rates established by the DPU for NSTAR Electric and WMECO are comprised of the following:


·

A basic service charge that represents the collection of energy costs, including costs related to charge-offs of uncollected energy costs from customers.  Electric distribution companies in Massachusetts are required to obtain and resell power to retail customers through basic service for those who choose not to buy energy from a competitive energy supplier.  Basic service rates are reset every six months (every three months for large commercial and industrial customers).  Additionally, the DPU has authorized NSTAR Electric to recover the cost of its Dynamic Pricing Smart Grid Pilot Program through the basic service charge.  Basic service costs are reconciled annually.


·

A distribution charge, which includes a fixed customer charge and a demand and/or energy charge to collect the costs of building and expanding the infrastructure to deliver power to its destination, as well as ongoing operating costs.


·

For WMECO, a revenue decoupling adjustment that reconciles distribution revenue, on an annual basis, to the amount of distribution revenue approved by the DPU in its last rate case in 2011.  Currently, WMECO is allowed to collect $132.4 million annually.


·

A transmission charge that recovers the cost of transporting electricity over high voltage lines from generating plants to substations, including costs allocated by ISO-NE to maintain the wholesale electric market.


·

A transition charge that represents costs to be collected primarily from previously held investments in generating plants, costs related to existing above-market power contracts, and contract costs related to long-term power contract buy-outs.


·

An energy efficiency charge that represents a legislatively-mandated charge to collect costs for energy efficiency programs.


·

Reconciling adjustment charges that recover certain DPU-approved costs as follows:  pension and PBOP benefits, low income customer discounts, lost revenue and credits associated with net-metering facilities installed by customers, storms, consultants retained by the attorney general, and energy efficiency programs and lost base revenue not recovered in the energy efficiency charge.  In addition to these adjustments common to both NSTAR Electric and WMECO, NSTAR Electric has reconciling adjustment charges that collect costs associated with certain safety and reliability projects, a Smart Grid pilot program, and long-term renewable contracts.  WMECO has a reconciling adjustment charge that recovers costs associated with certain solar projects owned and operated by WMECO.  


As required by regulation, NSTAR Electric and WMECO, along with two other Massachusetts electric utilities, signed long-term commitments to purchase a combined estimated generating capacity of approximately 334 MW of wind power from two wind farms in Maine over 15 years.  The projects are in various stages of permitting or development and are expected to begin operation in 2015 and 2016.


Pursuant to a 2008 DPU order, Massachusetts electric utilities must adopt rate structures that decouple the volume of energy sales from the utility's revenues in their next rate case.  WMECO is currently decoupled and NSTAR Electric will propose decoupling in its next rate case.  


NSTAR Electric and WMECO are each subject to service quality (SQ) metrics that measure safety, reliability and customer service, and could be required to pay to customers a SQ charge of up to 2.5 percent of annual transmission and distribution revenues for failing to meet such metrics.  Neither NSTAR Electric nor WMECO will be required to pay a SQ charge for its 2014 performance as each company achieved results at or above target for all of its respective SQ metrics in 2014.


Sources and Availability of Electric Power Supply


As noted above, neither NSTAR Electric nor WMECO owns any generation assets (other than WMECO's solar generation), and both companies purchase their respective energy requirements from a variety of competitive sources through requests for proposals issued periodically, consistent with DPU regulations.  NSTAR Electric and WMECO enter into supply contracts for basic service for 50 percent of their respective residential and small commercial and industrial customers twice per year for twelve month terms.  Both NSTAR Electric and WMECO enter into supply contracts for basic service for 100 percent of large commercial and industrial customers every three months.


ELECTRIC DISTRIBUTION – NEW HAMPSHIRE


PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE


PSNH's distribution business consists primarily of the generation, delivery and sale of electricity to its residential, commercial and industrial customers.  As of December 31, 2014, PSNH furnished retail franchise electric service to approximately 504,000 retail customers in 211 cities and towns in New Hampshire, covering an area of approximately 5,630 square miles.  PSNH also owns and operates approximately 1,200 MW of primarily coal- and oil-fired electricity generation plants.  PSNH's distribution business includes the activities of its generation business.


The Clean Air Project, a wet flue gas desulphurization system (Scrubber), was constructed and placed in service by PSNH at its Merrimack Station in 2011.  Tests to date indicate that the Scrubber reduces emissions of SO2 and mercury from Merrimack Station by over 90 percent, which is well in excess of state and federal requirements.  PSNH is permitted to recover prudent Scrubber costs through its ES rates under New Hampshire law.  In 2011, the NHPUC opened a docket to review the Clean Air Project.  For further information, see "Regulatory Developments and Rate Matters – New Hampshire – Clean Air Project Prudence Proceeding" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.




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The following table shows the sources of PSNH's 2014 electric franchise retail revenues based on categories of customers:


 

PSNH

(Thousands of Dollars, except percentages)

 

2014

 

% of Total

Residential

$

478,753 

 

54 

Commercial

 

299,538 

 

34 

Industrial

 

72,624 

 

Other

 

37,544 

 

Total Retail Electric Revenues

$

888,459 

 

100%


A summary of PSNH's retail electric GWh sales volumes and percentage changes for 2014, as compared to 2013, is as follows:


 

2014

 

2013

 

Percentage
Change

Residential 

3,172 

 

 3,208 

 

(1.1)%

Commercial

3,332 

 

 3,357 

 

(0.8)%

Industrial 

1,382 

 

 1,373 

 

0.6  %

Total

7,886 

 

 7,938 

 

(0.7)%


Rates


PSNH is subject to regulation by the NHPUC, which, among other things, has jurisdiction over rates, certain dispositions of property and plant, mergers and consolidations, issuances of securities, standards of service and construction and operation of facilities.  New Hampshire utilities are entitled under state law to charge rates that are sufficient to allow them an opportunity to recover their reasonable operating and capital costs, in order to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.


Under New Hampshire law, all of PSNH's customers are entitled to choose competitive energy suppliers, with PSNH providing default energy service under its ES rate for those customers who do not choose a competitive energy supplier.  At the end of 2014, approximately 21 percent of all of PSNH's customers (approximately 46 percent of load) were taking service from competitive energy suppliers, compared to 25 percent of customers (approximately 54 percent of load) at the end of 2013.  


The rates established by the NHPUC for PSNH are comprised of the following:


·

A default energy service charge (ES) is charged to customers who have selected not to receive their energy supply from a competitive energy supplier.  These charges recover the costs of PSNH's generation, as well as purchased power, and include the NHPUC allowed ROE of 9.81 percent on PSNH's generation investment.


·

A distribution charge, which includes an energy and/or demand-based charge to recover costs related to the maintenance and operation of PSNH's infrastructure to deliver power to its destination, as well as power restoration and service costs.  This includes a customer charge to collect the cost of providing service to a customer; such as the installation, maintenance, reading and replacement of meters and maintaining accounts and records.  


·

A transmission charge that recovers the cost of transporting electricity over high voltage lines from generating plants to substations, including costs allocated by ISO-NE to maintain the wholesale electric market.


·

A stranded cost recovery charge (SCRC), which allows PSNH to recover its stranded costs, including above-market expenses incurred under mandated power purchase obligations and other long-term investments and obligations.  PSNH had financed a significant portion of its stranded costs through securitization by issuing RRBs secured by the right to recover these stranded costs from customers over the life of the RRBs.  The costs of the RRBs, which were retired on May 1, 2013, were recovered through the SCRC rate.


·

A systems benefits charge (SBC), which funds energy efficiency programs for all customers as well as assistance programs for residential customers within certain income guidelines.


·

An electricity consumption tax, which is a state mandated tax on energy consumption.


The energy charge and SCRC rates change semi-annually and are reconciled annually and recovered in subsequent rates.  The Rate ADE reconciliation amount is incorporated into the ES reconciliation.


PSNH is currently operating under the 2010 NHPUC approved distribution rate case settlement, which is effective through June 30, 2015.  Under the settlement, PSNH is permitted to file a request to collect certain exogenous costs and step increases on an annual basis.  


Generation Assets


In 2013, the NHPUC opened a docket that initiated a series of actions throughout 2013 and 2014 regarding the potential divestiture of PSNH's generating plants, including actions by the NHPUC staff, the State of New Hampshire Legislative Oversight Committee on Electric Utility Restructuring (Oversight Committee), a valuation expert, and the New Hampshire Legislature.  During the 2014 Legislative session, in response to an NHPUC staff recommendation to harmonize existing laws regarding divestiture, energy service, and cost recovery, the Legislature enacted changes to the laws governing divestiture of PSNH's generation assets, effective September 30, 2014.  The new law required the NHPUC to initiate a



7


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.  A progress report from the NHPUC must be provided to the Oversight Committee by March 31, 2015.  The law 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.  For further information, see "Regulatory Developments and Rate Matters – New Hampshire - Generation" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.


Sources and Availability of Electric Power Supply


During 2014, approximately 59 percent of PSNH's load was met through its own generation, long-term power supply provided pursuant to orders of the NHPUC, and contracts with competitive energy suppliers.  The remaining 41 percent of PSNH's load was met by short-term (less than one year) purchases and spot purchases in the competitive New England wholesale power market.  PSNH expects to meet its load requirements in 2015 in a similar manner.  Included in the 59 percent above are PSNH's obligations to purchase power from approximately two dozen IPPs, the output of which it either uses to serve its customer load or sells into the ISO-NE market.


Merrimack, Schiller and the Hydro stations have been operating at very high capacity factors during this current winter season,   As a result of our diverse fuel mix, PSNH's Energy Service rate has been set at 10.56 cents per kWh, well below the winter default service rates in excess of 15 cents per kWh for the two other investor owned utilities in the state.


MAJOR STORMS


CL&P, NSTAR Electric, PSNH and WMECO experienced several significant storm events, including Tropical Storm Irene in 2011, the October 2011 snowstorm, Storm Sandy in 2012, the February 2013 blizzard, and a November 2014 snowstorm.  As a result of these storm events, each company suffered extensive damage to its distribution and transmission systems resulting in customer outages.  Each company incurred significant costs to repair damage and restore customers' service.  


The magnitude of these storm restoration costs met the criteria for cost deferral in Connecticut, Massachusetts, and New Hampshire.  As a result, the storms had no material impact on the results of operations of CL&P, NSTAR Electric, PSNH and WMECO.  We believe the storm restoration costs were prudent and meet the criteria for specific cost recovery in Connecticut, Massachusetts and New Hampshire, and that recovery from customers is probable through the applicable regulatory recovery process.  Each electric utility has sought, or is seeking, recovery of its deferred storm restoration costs through its applicable regulatory recovery process.  For further information, see "Regulatory Developments and Rate Matters" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.  


ELECTRIC TRANSMISSION SEGMENT


General


Each of CL&P, NSTAR Electric, PSNH and WMECO owns and maintains transmission facilities that are part of an interstate power transmission grid over which electricity is transmitted throughout New England.  Each of CL&P, NSTAR Electric, PSNH and WMECO, and most other New England utilities, are parties to a series of agreements that provide for coordinated planning and operation of the region's transmission facilities and the rules by which they acquire transmission services.  Under these arrangements, ISO-NE, a non-profit corporation whose board of directors and staff are independent of all market participants, serves as the regional transmission organization of the New England transmission system.  


Wholesale Transmission Revenues


A summary of NU's wholesale transmission revenues is as follows:


(Thousands of Dollars)

 

2014

CL&P

$

507,182

NSTAR Electric

 

275,377

PSNH

 

114,963

WMECO

 

120,803

Total Wholesale Transmission Revenues

$

1,018,325


Wholesale Transmission Rates


Wholesale transmission revenues are recovered through FERC approved formula rates.  Transmission revenues are collected from New England customers, the majority of which are distribution customers of CL&P, NSTAR Electric, PSNH and WMECO.  The transmission rates provide for the annual reconciliation of estimated to actual costs.  The financial impacts of differences between actual and estimated costs are deferred for future recovery from, or refunded to, transmission customers.




8


FERC Base ROE Complaints


Beginning in 2011, several New England state attorneys general, state regulatory commissions, consumer advocates, consumer groups, municipal parties and other parties (the "Complainants") jointly filed three separate complaints at FERC.  In the first complaint, filed in 2011, the Complainants alleged that the NETOs' base ROE of 11.14 percent that was utilized since 2006 was unjust and unreasonable, asserted that the rate was excessive due to changes in the capital markets, and sought an order to reduce it prospectively from the date of the final FERC order and for the 15-month period beginning October 1, 2011 to December 31, 2012 (the "first complaint refund period").  In the pursuant second and third complaints, filed in 2012 and 2014, respectively, the Complainants challenged the NETOs' base ROE and sought refunds for the 15-month periods beginning December 27, 2012 and July 31, 2014, respectively.


In 2014, the FERC determined that the base ROE should be set at 10.57 percent for the first complaint refund period and that a utility's total or maximum ROE should not exceed the top of the new zone of reasonableness (7.03 percent to 11.74 percent).  The FERC ordered the NETOs to provide refunds to customers for the first complaint refund period and set the new base ROE of 10.57 percent prospectively from October 16, 2014.  In late 2014, the NETOs made a compliance filing, and began refunding amounts from the first complaint period, inclusive of incentive ROE adders that exceeded the 11.74 percent as compared to the total company transmission ROE.  Complainants have challenged the compliance filing.


As a result of the actions taken by the FERC and other developments in this matter, NU recorded reserves in 2013 and 2014 to recognize the potential financial impacts of the first and second complaints.  The Company is unable to determine any amount related to the third complaint.  The aggregate after-tax net charge to 2014 earnings resulting from the 2014 FERC orders totaled $22.4 million at NU.  In 2013, the aggregate after-tax charge to earnings totaled $14.3 million at NU.


Although management is uncertain on the final outcome on the second and third complaints regarding the base ROE and the incentive ROE adder, management believes the current reserves established are appropriate to reflect probable and reasonably estimable refunds.  For further information, see "FERC Regulatory Issues – FERC Base ROE Complaints" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.  


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 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.


Transmission Projects


During 2014, we were involved in the planning, development and construction of a series of transmission projects, including the NEEWS family of projects, Northern Pass, which 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, and Greater Boston Reliability Solutions, which are a series of new transmission projects over the next five years that will enhance system reliability and improve capacity.  For further information, see "Business Development and Capital Expenditures – Transmission Business" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.


Transmission Rate Base


Under our FERC-approved tariff, and with the exception of transmission projects that received specific FERC approval to include CWIP in rate base, transmission projects generally enter rate base after they are placed in commercial operation.  At the end of 2014, our estimated transmission rate base was approximately $4.9 billion, including approximately $2.4 billion at CL&P, $1.3 billion at NSTAR Electric, $535 million at PSNH, and $611 million at WMECO.  




9


NATURAL GAS DISTRIBUTION SEGMENT


NSTAR Gas distributes natural gas to approximately 282,000 customers in 51 communities in central and eastern Massachusetts covering 1,067 square miles and Yankee Gas distributes natural gas to approximately 222,000 customers in 71 cities and towns in Connecticut covering 2,187 square miles.  Total throughput (sales and transportation) in 2014 was approximately 60.5 Bcf for NSTAR Gas and 55 Bcf for Yankee Gas.  Our natural gas businesses provide firm natural gas sales service to retail customers who require a continuous natural gas supply throughout the year, such as residential customers who rely on natural gas for heating, hot water and cooking needs, and commercial and industrial customers who choose to purchase natural gas from NU's natural gas distribution companies.  A portion of the storage of natural gas supply for NSTAR Gas during the winter heating season is provided by Hopkinton LNG Corp., an indirect, wholly-owned subsidiary of NU.  The facilities consist of an LNG liquefaction and vaporization plant and three above-ground cryogenic storage tanks in Hopkinton, Massachusetts having an aggregate capacity of 3.0 Bcf of liquefied natural gas.  NSTAR Gas also has access to facilities in Acushnet, Massachusetts that include additional storage capacity of 0.5 Bcf and additional vaporization capacity.  Yankee Gas owns a 1.2 Bcf LNG facility in Waterbury, Connecticut, which is used primarily to assist Yankee Gas in meeting its supplier-of-last-resort obligations and also enables it to provide economic supply and make economic refill of natural gas typically during periods of low demand.  


NSTAR Gas and Yankee Gas generate revenues primarily through the sale and/or transportation of natural gas.  Predominantly all residential customers in the NSTAR Gas service territory buy gas supply and delivery from NSTAR Gas while all customers may choose their gas suppliers.  Retail natural gas service in Connecticut is partially unbundled: residential customers in Yankee Gas' service territory buy natural gas supply and delivery only from Yankee Gas while commercial and industrial customers may choose their natural gas suppliers.  NSTAR Gas offers firm transportation service to all customers who purchase gas from sources other than NSTAR Gas while Yankee Gas offers firm transportation service to its commercial and industrial customers who purchase natural gas from sources other than Yankee Gas.  In addition, both natural gas distribution companies offer interruptible transportation and interruptible natural gas sales service to those high volume commercial and industrial customers, generally during the colder months, that have the capability to switch from natural gas to an alternative fuel on short notice, for whom NSTAR Gas and Yankee Gas can interrupt service during peak demand periods or at any other time to maintain distribution system integrity.


The following table shows the sources of the 2014 total NU natural gas franchise retail revenues based on categories of customers:


(Thousands of Dollars, except percentages)

 

2014

 

% of Total

Residential

$

520,410 

 

55 

Commercial

 

332,414 

 

35 

Industrial

 

94,861 

 

10 

Total Retail Natural Gas Revenues

$

947,685 

 

100%


A summary of our firm natural gas sales volumes in million cubic feet and percentage changes for 2014, as compared to 2013, is as follows:


 

 

 

Percentage

 

2014

 

2013

 

Change

Residential

38,969 

 

36,777 

 

6.0%

Commercial

42,977 

 

40,215 

 

6.9%

Industrial

22,245 

 

21,266 

 

4.6%

Total

104,191 

 

98,258 

 

6.0%

Total, Net of Special Contracts (1)

99,500 

 

94,083 

 

5.8%


 (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.


Our firm natural gas sales are subject to many of the same influences as our retail electric sales.  In addition, they have benefited from favorable natural gas prices and customer growth across both operating companies.  Our 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 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 2014, as compared to 2013.  Weather-normalized NU consolidated firm natural gas sales volumes increased 2.9 percent in 2014, as compared to 2013.  


Rates


NSTAR Gas and Yankee Gas are subject to regulation by the DPU and PURA, respectively, which, among other things, have jurisdiction over rates, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service and construction and operation of facilities.  Both of NU's natural gas companies are entitled under their respective state law to charge rates that are sufficient to allow them an opportunity to recover their reasonable operating and capital costs, in order to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.


Retail natural gas delivery and supply rates are established by the DPU and PURA and are comprised of:


·

A distribution charge consisting of a fixed customer charge and a demand and/or energy charge that collects the costs of building and expanding the natural gas infrastructure to deliver natural gas supply to its customers.  This also includes collection of ongoing operating costs;


·

A seasonal cost of gas adjustment clause (CGAC) at NSTAR Gas that collects natural gas supply costs, pipeline and storage capacity costs, costs related to charge-offs of uncollected energy costs and working capital related costs.  The CGAC is reset semi-annually.  In addition,



10


NSTAR Gas files interim changes to its CGAC factor when the actual costs of natural gas supply vary from projections by more than five percent; and


·

A local distribution adjustment clause (LDAC) at NSTAR Gas that collects energy efficiency program costs, environmental costs, pension and PBOP related costs, energy efficiency costs, attorney general consultant costs, and costs associated with low income customers.  The LDAC is reset annually and provides for the recovery of certain costs applicable to both sales and transportation customers.


·

Purchased Gas Adjustment (PGA) clause, which allows Yankee Gas to recover the costs of the procurement of natural gas for its firm and seasonal customers.  Differences between actual natural gas costs and collection amounts on August 31st of each year are deferred and then recovered from or refunded to customers during the following year.  Carrying charges on outstanding balances are calculated using Yankee Gas' weighted average cost of capital in accordance with the directives of the PURA; and


·

Conservation Adjustment Mechanism (CAM) at Yankee Gas, which allows 100 percent recovery of conservation costs through this mechanism including program incentives to promote energy efficiency, as well as recovery of any lost revenues associated with implementation of energy conservation measures.  A reconciliation of CAM revenues to expenses is performed annually with any difference being recovered from or refunded to customers, with carrying charges, during the following year.


NSTAR Gas purchases financial contracts based on NYMEX natural gas futures in order to reduce cash flow variability associated with the purchase price for approximately one-third of its natural gas purchases.  These purchases are made under a program approved by the DPU in 2006.  This practice attempts to minimize the impact of fluctuations in natural gas prices to NSTAR Gas' firm natural gas customers.  These financial contracts do not procure natural gas supply.  All costs incurred or benefits realized when these contracts are settled are included in the CGAC.


NSTAR Gas is subject to SQ metrics that measure safety, reliability and customer service and could be required to pay to customers a SQ charge of up to 2.5 percent of annual distribution revenues for failing to meet such metrics.  NSTAR Gas will not be required to pay a SQ charge for its 2014 performance as it achieved results at or above target for all of its SQ metrics in 2014.


On December 17, 2014, NSTAR Gas filed an application with the DPU requesting an increase in rates, effective January 1, 2016.  NSTAR Gas requested an increase in base distribution rates of $33.9 million.  Based on the current schedule, we expect a final decision in the fourth quarter of 2015.  


In 2011, PURA approved Yankee Gas' rate proceeding.  The final decision approved a regulatory ROE of 8.83 percent and allowed for a substantial increase in annual spending for bare steel and cast iron pipeline replacement.


Massachusetts Natural 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.  NSTAR Gas' program accelerates the replacement of certain natural gas distribution facilities in the system within 25 years.  The GSEP includes a new tariff that provides NSTAR Gas an opportunity to collect the costs for the program on an annual basis through a newly designed reconciling factor to be approved by the DPU.  We expect a decision on the program in April 2015.


Connecticut Natural Gas Expansion Plan


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


Sources and Availability of Natural Gas Supply


NSTAR Gas maintains a flexible resource portfolio consisting of natural gas supply contracts, transportation contracts on interstate pipelines, market area storage and peaking services.  NSTAR Gas purchases transportation, storage, and balancing services from Tennessee Gas Pipeline Company and Algonquin Gas Transmission Company, as well as other upstream pipelines that transport gas from major producing regions in the U.S., including the Gulf Coast, Mid-continent region, and Appalachian Shale supplies to the final delivery points in the NSTAR Gas service area.  NSTAR Gas purchases all of its natural gas supply under a firm portfolio management contract with a term of one year, which has a maximum quantity of approximately 154,700 MMBtu/day of firm flowing natural gas supplies and 76,700 MMBtu/day of firm natural gas storage supplies.


In addition to the firm transportation and natural gas supplies mentioned above, NSTAR Gas utilizes contracts for underground storage and LNG facilities to meet its winter peaking demands.  The LNG facilities, described below, are located within NSTAR Gas' distribution system and are used to liquefy and store pipeline natural gas during the warmer months for vaporization and use during the heating season.  During the summer injection season, excess pipeline capacity and supplies are used to deliver and store natural gas in market area underground storage facilities located in the



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New York and Pennsylvania regions.  Stored natural gas is withdrawn during the winter season to supplement flowing pipeline supplies in order to meet firm heating demand.  NSTAR Gas has firm underground storage contracts and total storage capacity entitlements of approximately 6.6 Bcf.


A portion of the storage of natural gas supply for NSTAR Gas during the winter heating season is provided by Hopkinton LNG Corp., which owns an LNG liquefaction and vaporization plant and three above-ground cryogenic storage tanks having an aggregate capacity of 3.0 Bcf of liquefied natural gas.  NSTAR Gas also has access to facilities that include additional storage capacity of 0.5 Bcf and additional vaporization capacity.


PURA requires that Yankee Gas meet the needs of its firm customers under all weather conditions.  Specifically, Yankee Gas must structure its supply portfolio to meet firm customer needs under a design day scenario (defined as the coldest day in 30 years) and under a design year scenario (defined as the average of the four coldest years in the last 30 years).  Yankee Gas' on-system stored LNG and underground storage supplies help to meet consumption needs during the coldest days of winter.  Yankee Gas obtains its interstate capacity from the three interstate pipelines that directly serve Connecticut: the Algonquin, Tennessee and Iroquois Pipelines.  Yankee Gas has long-term firm contracts for capacity on TransCanada Pipelines Limited Pipeline, Vector Pipeline, L.P., Tennessee Gas Pipeline, Iroquois Gas Transmission Pipeline, Algonquin Pipeline, Union Gas Limited, Dominion Transmission, Inc., National Fuel Gas Supply Corporation, Transcontinental Gas Pipeline Company, and Texas Eastern Transmission, L.P. pipelines.  


Based on information currently available regarding projected growth in demand and estimates of availability of future supplies of pipeline natural gas, NSTAR Gas and Yankee Gas each believes that participation in planned and anticipated pipeline expansion projects will be required in order for it to meet current and future sales growth opportunities.


NATURAL GAS PIPELINE EXPANSION


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.  On February 18, 2015, NU, Spectra Energy Corp and National Grid announced the addition of National Grid as a co-developer in the project for a total ownership interest of 20 percent, with NU and Spectra Energy Corp each owning 40 percent.  The total project cost, subject to FERC approval, is expected to be approximately $3 billion and has an anticipated in-service date of November 2018.


On December 8, 2014, NU and Spectra Energy Corp announced an alliance with Iroquois Gas Transmission for the Access Northeast project.  This alliance will provide New England natural gas distribution companies and generators with additional access to natural gas supplies from multiple, diverse receipt points along the Algonquin pipeline system, including the Iroquois pipeline system.


PROJECTED CAPITAL EXPENDITURES


We project to make capital expenditures of approximately $8.4 billion from 2015 through 2018.  Of the $8.4 billion, we expect to invest approximately $4.2 billion in our electric and natural gas distribution segments and $3.9 billion in our electric transmission segment.  In addition, we project to invest approximately $360 million in information technology and facilities upgrades and enhancements.  These projections do not include capital expenditures related to Access Northeast.


FINANCING


Our credit facilities and indentures require that NU parent and certain of its subsidiaries, including CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO and Yankee Gas, comply with certain financial and non-financial covenants as are customarily included in such agreements, including maintaining a ratio of consolidated debt to total capitalization of no more than 65 percent.  All of these companies currently are, and expect to remain, in compliance with these covenants.  


As of December 31, 2014, a total of $216.7 million of NU's long-term debt will be paid in the next 12 months, consisting of $162 million for CL&P, $4.7 million for NSTAR Electric and $50 million or WMECO.  


NUCLEAR FUEL STORAGE


CL&P, NSTAR Electric, PSNH, WMECO and several other New England electric utilities are stockholders in three inactive regional nuclear generation companies, CYAPC, MYAPC and YAEC (collectively, the Yankee Companies).  The Yankee Companies have completed the physical decommissioning of their respective generation facilities and are now engaged in the long-term storage of their spent nuclear fuel.  Each Yankee Company has completed its collection of decommissioning and closure costs through the proceeds from the spent nuclear fuel litigation against the DOE.  These proceeds were used by the Yankee Companies to offset the decommissioning and closure cost receivables from their member companies or to decrease the wholesale FERC-approved rates charged under power purchase agreements with CL&P, NSTAR Electric, PSNH and WMECO and several other New England utilities.  The decommissioning rates charged by the Yankee Companies have been eliminated.  CL&P, NSTAR Electric, PSNH and WMECO can recover these costs from, or refund proceeds to, their customers through state regulatory commission-approved retail rates.  


As a result of the merger with NSTAR, we consolidate the assets and obligations of CYAPC and YAEC on our consolidated balance sheet.  


For information on the DOE proceeds received related to the spent nuclear fuel litigation, see Note 11C, “Commitments and Contingencies – Contractual Obligations – Yankee Companies,” in the accompanying Item 8, Financial Statements and Supplementary Data.




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OTHER REGULATORY AND ENVIRONMENTAL MATTERS


General


We are regulated in virtually all aspects of our business by various federal and state agencies, including FERC, the SEC, and various state and/or local regulatory authorities with jurisdiction over the industry and the service areas in which each of our companies operates, including the PURA, which has jurisdiction over CL&P and Yankee Gas, the NHPUC, which has jurisdiction over PSNH, and the DPU, which has jurisdiction over NSTAR Electric, NSTAR Gas and WMECO.


Environmental Regulation


We are subject to various federal, state and local requirements with respect to water quality, air quality, toxic substances, hazardous waste and other environmental matters.  Additionally, major generation and transmission facilities may not be constructed or significantly modified without a review of the environmental impact of the proposed construction or modification by the applicable federal or state agencies.  


Water Quality Requirements


The Clean Water Act requires every "point source" discharger of pollutants into navigable waters to obtain a National Pollutant Discharge Elimination System (NPDES) permit from the EPA or state environmental agency specifying the allowable quantity and characteristics of its effluent.  States may also require additional permits for discharges into state waters.  We are in the process of maintaining or renewing all required NPDES or state discharge permits in effect for PSNH's generation facilities.  


In 1997, PSNH filed in a timely manner for a renewal of the NPDES permit for the Merrimack Station.  As a result, the existing permit was administratively continued.  In 2011, the EPA issued a draft renewal NPDES permit for PSNH's Merrimack Station for public review and comment.  The proposed permit contains many significant conditions to future operation.  The proposed permit would require PSNH to install a closed-cycle cooling system (including cooling towers) at the station.  The EPA estimated that the net present value cost to install this system and operate it over a 20-year period would be approximately $112 million.  PSNH and other electric utility groups filed thousands of pages of comments contesting EPA's draft permit requirements.  PSNH stated that the data and studies supplied to the EPA demonstrate the fact that a closed-cycle cooling system is not warranted.  On April 18, 2014 EPA issued a revised section of the draft NPDES permit for Merrimack Station.  The revised portion of the draft permit deals solely with the treatment of wastewater from the flue gas desulfurization system.  On August 18, 2014 PSNH again submitted comments.  The EPA does not have a set deadline to consider comments and to issue a final permit.  Merrimack Station is permitted to continue to operate under its present permit pending issuance of the final permit and subsequent resolution of matters appealed by PSNH and other parties.  Due to the site specific characteristics of PSNH's other coal- and oil-fired electric generating stations, we believe it is unlikely that they would face similar permitting determinations.


Air Quality Requirements


The Clean Air Act Amendments (CAAA), as well as New Hampshire law, impose stringent requirements on emissions of SO2 and NOX for the purpose of controlling acid rain and ground level ozone.  In addition, the CAAA address the control of toxic air pollutants.  Requirements for the installation of continuous emissions monitors and expanded permitting provisions also are included.


In 2011, the EPA finalized the Mercury and Air Toxic Standards (MATS) that require the reduction of emissions of hazardous air pollutants from new and existing coal- and oil-fired electric generating stations.  Previously referred to as the Utility MACT (maximum achievable control technology) rules, it establishes emission limits for mercury, arsenic and other hazardous air pollutants from coal- and oil-fired electric generating stations.  MATS is the first implementation of a nationwide emissions standard for hazardous air pollutants across all electric generating units and provides utility companies with up to five years to meet the requirements.  PSNH owns and operates approximately 1,000 MW of coal- and oil-fired electric generating stations subject to MATS, including the two units at Merrimack Station, Newington Station and the two coal units at Schiller Station.  We believe the Clean Air Project at our Merrimack Station, together with existing equipment, will enable the facility to meet the MATS requirements.  At Schiller Station additional controls are being installed at the two coal-fired units, the cost of which is estimated to be approximately $2.5 million.


Each of the states in which we do business also has Renewable Portfolio Standards (RPS) requirements, which generally require fixed percentages of our energy supply to come from renewable energy sources such as solar, hydropower, landfill gas, fuel cells and other similar sources.  


New Hampshire's RPS provision requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources.  In 2014, the total RPS obligation was 9.7 percent and it will ultimately reach 24.8 percent in 2025.  Energy suppliers, like PSNH, purchase RECs from producers that generate energy from a qualifying resource and use them to satisfy the RPS requirements.  PSNH also owns renewable sources and uses a portion of internally generated RECs to meet its RPS obligations.  To the extent that PSNH is unable to purchase sufficient RECs, it makes up the difference between the RECs purchased and its total obligation by making an alternative compliance payment for each REC requirement for which PSNH is deficient.  The costs of both the RECs and alternative compliance payments are recovered by PSNH through its ES rates charged to customers.  


The RECs generated from PSNH's Northern Wood Power Project, a wood-burning facility, are typically sold to other energy suppliers or load carrying entities, and the net proceeds from the sale of these RECs are credited back to customers.


Similarly, Connecticut's RPS statute requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources.  In 2014, the total RPS obligation was 18 percent and will ultimately reach 27 percent in 2020.  CL&P is permitted to recover any costs incurred in complying with RPS from its customers through its GSC rate.



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Massachusetts' RPS program also requires electricity suppliers to meet renewable energy standards.  For 2014, the requirement was 16.1 percent, and will ultimately reach 22.1 percent in 2020.  NSTAR Electric and WMECO are permitted to recover any costs incurred in complying with RPS from its customers through rates.  WMECO also owns renewable solar generation resources.  The RECs generated from WMECO's solar units are sold to other energy suppliers, and the proceeds from these sales are credited back to customers.


Hazardous Materials Regulations


Prior to the last quarter of the 20th century, when environmental best practices laws and regulations were implemented, utility companies often disposed of residues from operations by depositing or burying them on-site or disposing of them at off-site landfills or other facilities.  Typical materials disposed of include coal gasification byproducts, fuel oils, ash, and other materials that might contain polychlorinated biphenyls or that otherwise might be hazardous.  It has since been determined that deposited or buried wastes, under certain circumstances, could cause groundwater contamination or create other environmental risks.  We have recorded a liability for what we believe, based upon currently available information, is our reasonably estimable environmental investigation and/or remediation costs for waste disposal sites for which we have probable liability.  We continue to evaluate the environmental impact of our former disposal practices.  Under federal and state law, government agencies and private parties can attempt to impose liability on us for these practices.  As of December 31, 2014, the liability recorded for our reasonably estimable and probable environmental remediation costs for known sites needing investigation and/or remediation, exclusive of recoveries from insurance or from third parties, was approximately $43.3 million, representing 65 sites.  These costs could be significantly higher if remediation becomes necessary or when additional information as to the extent of contamination becomes available.


The most significant liabilities currently relate to future clean-up costs at former MGP facilities.  These facilities were owned and operated by our predecessor companies from the mid-1800's to mid-1900's.  By-products from the manufacture of gas using coal resulted in fuel oils, hydrocarbons, coal tar, purifier wastes, metals and other waste products that may pose risks to human health and the environment.  We currently have partial or full ownership responsibilities at former MGP sites that have a reserve balance of $38.8 million of the total $43.3 million as of December 31, 2014.  Predominantly all of these MGP costs are recoverable from customers through our rates.


Electric and Magnetic Fields  


For more than twenty years, published reports have discussed the possibility of adverse health effects from electric and magnetic fields (EMF) associated with electric transmission and distribution facilities and appliances and wiring in buildings and homes.  Although weak health risk associations reported in some epidemiology studies remain unexplained, most researchers, as well as numerous scientific review panels, considering all significant EMF epidemiology and laboratory studies, have concluded that the available body of scientific information does not support the conclusion that EMF affects human health.


In accordance with recommendations of various regulatory bodies and public health organizations, we reduce EMF associated with new transmission lines by the use of designs that can be implemented without additional cost or at a modest cost.  We do not believe that other capital expenditures are appropriate to minimize unsubstantiated risks.


Global Climate Change and Greenhouse Gas Emission Issues


Global climate change and greenhouse gas emission issues have received an increased focus from state governments and the federal government.  The EPA initiated a rulemaking addressing greenhouse gas emissions and, on December 7, 2009, issued a finding that concluded that greenhouse gas emissions are "air pollution" that endanger public health and welfare and should be regulated.  The largest source of greenhouse gas emissions in the U.S. is the electricity generating sector.  The EPA has mandated greenhouse gas emission reporting beginning in 2011 for emissions for certain aspects of our business including stationary combustion, volume of gas supplied to large customers and fugitive emissions of SF6 gas and methane.


We are continually evaluating the regulatory risks and regulatory uncertainty presented by climate change concerns.  Such concerns could potentially lead to additional rules and regulations that impact how we operate our business, both in terms of the generating facilities we own and operate as well as general utility operations.  These could include federal "cap and trade" laws, carbon taxes, fuel and energy taxes, or regulations requiring additional capital expenditures at our generating facilities.  We expect that any costs of these rules and regulations would be recovered from customers.


Connecticut, New Hampshire and Massachusetts are each members of the Regional Greenhouse Gas Initiative (RGGI), a cooperative effort by nine northeastern and mid-Atlantic states, to develop a regional program for stabilizing and reducing CO2 emissions from coal- and oil-fired electric generating plants.  Because CO2 allowances issued by any participating state are usable across all nine RGGI state programs, the individual state CO2 trading programs, in the aggregate, form one regional compliance market for CO2 emissions.  A regulated power plant must hold CO2 allowances equal to its emissions to demonstrate compliance at the end of a three year compliance period that ended on December 31, 2014.


PSNH anticipates that its generating units will emit two million to three million tons of CO2 per year, depending on the capacity factor and the utilization of the respective generation plant, excluding emissions from the operation of PSNH's Northern Wood Power Project, which emissions are an offset.  New Hampshire legislation provided up to 1.5 million banked CO2 allowances per year for PSNH's coal- and oil-fired electric generating plants during the 2012 through 2014 compliance period.  PSNH satisfied its remaining RGGI requirements by purchasing CO2 allowances at auction or in the secondary market.  The cost of complying with RGGI requirements is recoverable from PSNH customers.  Current legislation provides that the portion of the RGGI auction proceeds in excess of $1 per allowance will be refunded to customers.


Because none of NU's other subsidiaries, CL&P, NSTAR Electric or WMECO, currently owns any generating assets (other than WMECO's solar photovoltaic facilities that do not emit CO2), none of them is required to acquire CO2 allowances.  However, the CO2 allowance costs borne by the



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generating facilities that are utilized by wholesale energy suppliers to satisfy energy supply requirements to CL&P, NSTAR Electric and WMECO will likely be included in the overall wholesale rates charged, which costs are then recoverable from customers.


FERC Hydroelectric Project Licensing


Federal Power Act licenses may be issued for hydroelectric projects for terms of 30 to 50 years as determined by the FERC.  Upon the expiration of an existing license, (i) the FERC may issue a new license to the existing licensee, (ii) the United States may take over the project, or (iii) the FERC may issue a new license to a new licensee, upon payment to the existing licensee of the lesser of the fair value or the net investment in the project, plus severance damages, less certain amounts earned by the licensee in excess of a reasonable rate of return.


PSNH owns nine hydroelectric generating stations with a current claimed capability representing winter rates of approximately 71 MW, eight of which are licensed by the FERC under long-term licenses that expire on varying dates from 2017 through 2047.  PSNH and its hydroelectric projects are subject to conditions set forth in such licenses, the Federal Power Act and related FERC regulations, including provisions related to the condemnation of a project upon payment of just compensation, amortization of project investment from excess project earnings, possible takeover of a project after expiration of its license upon payment of net investment and severance damages and other matters.  PSNH is currently in the early stages of relicensing its 6.5 MW Eastman Falls Hydro Station, the license for which expires in 2017.


EMPLOYEES


As of December 31, 2014, NU employed a total of 8,248 employees, excluding temporary employees, of which 1,548 were employed by CL&P, 1,717 were employed by NSTAR Electric 1,048 were employed by PSNH, and 310 were employed by WMECO.  Approximately 51 percent of our employees are members of the International Brotherhood of Electrical Workers, the Utility Workers Union of America or The United Steelworkers, and are covered by 13 collective bargaining agreements.


INTERNET INFORMATION


Our website address is www.eversource.com.  We make available through our website a link to the SEC's EDGAR website (http://www.sec.gov/edgar/searchedgar/companysearch.html), at which site NU's, CL&P's, NSTAR Electric's, PSNH's and WMECO's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports may be reviewed.  Information contained on the Company's website or that can be accessed through the website is not incorporated into and does not constitute a part of this Annual Report on Form 10-K.  Printed copies of these reports may be obtained free of charge by writing to our Investor Relations Department at Northeast Utilities, 107 Selden Street, Berlin, CT 06037.  


Item 1A.

Risk Factors


In addition to the matters set forth under "Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995" included immediately prior to Item 1, Business, above, we are subject to a variety of significant risks.  Our susceptibility to certain risks, including those discussed in detail below, could exacerbate other risks.  These risk factors should be considered carefully in evaluating our risk profile.


Cyber breaches, acts of war or terrorism, or grid disturbances could negatively impact our business.


Cyber breaches, acts of war or terrorism, physical attacks or grid disturbances resulting from internal or external sources could target our generation, transmission and distribution facilities or our information technology systems.  Such actions could impair our ability to manage these facilities, operate our systems effectively, or properly manage our data, networks and programs, resulting in loss of service to customers.  


Because our generation and transmission facilities are part of an interconnected regional grid, we face the risk of blackout due to a disruption on a neighboring interconnected system.  


Any such cyber breaches, acts of war or terrorism, physical attacks or grid disturbances could result in a significant decrease in revenues, significant expense to repair system damage or security breaches, and liability claims, which could have a material adverse impact on our financial position, results of operations or cash flows.


The unauthorized access to and the misappropriation of confidential and proprietary customer, employee, financial or system operating information could adversely affect our business operations and adversely impact our reputation.


In the regular course of business we maintain sensitive customer, employee, financial and system operating information and are required by various federal and state laws to safeguard this information.  Cyber intrusions, security breaches, theft or loss of this information by cyber crime or otherwise could lead to the release of critical operating information or confidential customer or employee information, which could adversely affect our business operations or adversely impact our reputation, and could result in significant costs, fines and litigation.  We maintain adequate privacy protection liability insurance to cover damages and defense costs arising from unauthorized disclosure of, or failure to protect, private information as well as costs for notification to, or for credit card monitoring of, customers, employees and other persons in the event of a breach of private information.  This insurance covers amounts paid to avert, prevent or stop a network attack or the disclosure of personal information, and costs of a qualified forensics firm to determine the cause, source and extent of a network attack or to investigate, examine and analyze our network to find the cause, source and extent of a data breach.  While we have implemented measures designed to prevent cyber-attacks and mitigate their effects should they occur, our systems are vulnerable to unauthorized access and cyber intrusions.  We cannot determine the probability that a security breach may occur or quantify the potential impact of such an event.




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The actions of regulators can significantly affect our earnings, liquidity and business activities.


The rates that our Regulated companies charge their customers are determined by their state utility commissions and by FERC.  These commissions also regulate the companies' accounting, operations, the issuance of certain securities and certain other matters.  FERC also regulates their transmission of electric energy, the sale of electric energy at wholesale, accounting, issuance of certain securities and certain other matters.  The commissions' policies and regulatory actions could have a material impact on the Regulated companies' financial position, results of operations and cash flows.


Our transmission, distribution and generation systems may not operate as expected, and could require unplanned expenditures, which could adversely affect our financial position, results of operations and cash flows.


Our ability to properly operate our transmission, distribution and generation systems is critical to the financial performance of our business.  Our transmission, distribution and generation businesses face several operational risks, including the breakdown or failure of or damage to equipment, including information technology equipment, or processes, especially due to age; labor disputes; disruptions in the delivery of electricity and natural gas, including impacts on us or our customers; increased capital expenditure requirements, including those due to environmental regulation; catastrophic events such as fires, explosions, or other similar occurrences; extreme weather conditions beyond equipment and plant design capacity; other unanticipated operations and maintenance expenses and liabilities; and potential claims for property damage or personal injuries beyond the scope of our insurance coverage.  The failure of our transmission, distribution and generation systems to operate as planned may result in increased capital costs, reduced earnings or unplanned increases in operation and maintenance costs.  As a result of our merger in 2012, we have implemented or expect to implement process and information technology system changes that are expected to provide significant improvements to our businesses.  If these changes do not result in the improvements that we expect, regulators may determine that the costs for these improvements are not prudent and therefore not recoverable from customers, which may result in reduced earnings. At PSNH, outages at generating stations may be deemed imprudent by the NHPUC resulting in disallowance of replacement power and repair costs.  Such costs that are not recoverable from our customers would have an adverse effect on our financial position, results of operations and cash flows.


We expect to invest in strategic development opportunities in both electric and natural gas transmission, but we may not be successful and projects may not commence operation as scheduled or be completed within budget, which could have a material adverse effect on our business prospects.


We are pursuing broader strategic development investment opportunities related to the construction of electric and natural gas transmission facilities, interconnections to generating resources and other investment opportunities.  The development, construction and expansion of electric transmission and natural gas transmission facilities involve numerous risks.  Various factors could result in increased costs or result in delays or cancellation of these projects.  Risks include regulatory approval processes, new legislation, economic events or factors, environmental and community concerns, design and siting issues, difficulties in obtaining required rights of way, competition from incumbent utilities and other entities, and actions of strategic partners.  Should any of these factors result in such delays or cancellations, our financial position, results of operations, and cash flows could be adversely affected or our future growth opportunities may not be realized as anticipated.


Economic events or factors, changes in regulatory or legislative policy and/or regulatory decisions or construction of new generation may delay completion of or displace or result in the abandonment of our planned transmission projects or adversely affect our ability to recover our investments or result in lower than expected earnings.


Our transmission construction plans could be adversely affected by economic events or factors, new legislation, regulations, or judicial or regulatory interpretations of applicable law or regulations or regulatory decisions.  Any of such events could cause delays in, or the inability to complete or abandonment of, economic or reliability related projects, which could adversely affect our ability to achieve forecasted earnings or to recover our investments or result in lower than expected rates of return.  Recoverability of all such investments in rates may be subject to prudence review at the FERC.  While we believe that all of such costs have been and will be prudently incurred, we cannot predict the outcome of future reviews should they occur.


In addition, our transmission projects may be delayed or displaced by new generation facilities, which could result in reduced transmission capital investments, reduced earnings, and limited future growth prospects.


Many of our transmission projects are expected to help alleviate identified reliability issues and reduce customers' costs.  However, if, due to economic events or factors or further regulatory or other delays, the in-service date for one or more of these projects is delayed, there may be increased risk of failures in the electricity transmission system and supply interruptions or blackouts, which could have an adverse effect on our earnings.


The FERC has followed a policy of providing incentives designed to encourage the construction of new transmission facilities, including higher returns on equity and allowing facilities under construction to be placed in rate base.  Our projected earnings and growth could be adversely affected were FERC to reduce these incentives in the future below the levels presently anticipated.


Increases in electric and gas prices and/or a weak economy, can lead to changes in legislative and regulatory policy promoting increased energy efficiency, conservation, and self-generation and/or a reduction in our customers' ability to pay their bills, which may adversely impact our business.


Energy consumption is significantly impacted by the general level of economic activity and cost of energy supply.  Economic downturns or periods of high energy supply costs typically can lead to the development of legislative and regulatory policy designed to promote reductions in energy consumption and increased energy efficiency and self-generation by customers.  This focus on conservation, energy efficiency and self-generation may result in a decline in electricity and natural gas sales in our service territories.  If any such declines were to occur without corresponding



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adjustments in rates at our Regulated companies that do not currently have revenue decoupling, then our revenues would be reduced and our future growth prospects would be limited.


In addition, a period of prolonged economic weakness could impact customers' ability to pay bills in a timely manner and increase customer bankruptcies, which may lead to increased bad debt expenses or other adverse effects on our financial position, results of operations or cash flows.


Changes in regulatory and/or legislative policy could negatively impact our transmission planning and cost allocation rules.


The existing FERC-approved New England transmission tariff allocates the costs of transmission facilities that provide regional benefits to all customers of participating transmission-owning utilities.  As new investment in regional transmission infrastructure occurs in any one state, its cost is shared across New England in accordance with a FERC approved formula found in the transmission tariff.  All New England transmission owners' agreement to this regional cost allocation is set forth in the Transmission Operating Agreement.  This agreement can be modified with the approval of a majority of the transmission owning utilities and approval by FERC.  In addition, other parties, such as state regulators, may seek certain changes to the regional cost allocation formula, which could have adverse effects on the rates our distribution companies charge their retail customers.  


FERC has issued rules requiring all regional transmission organizations and transmission owning utilities to make compliance changes to their tariffs and contracts in order to further encourage the construction of transmission for generation, including renewable generation.  This compliance will require ISO-NE and New England transmission owners to develop methodologies that allow for regional planning and cost allocation for transmission projects chosen in the regional plan that are designed to meet public policy goals such as reducing greenhouse gas emissions or encouraging renewable generation.  Such compliance may also allow non-incumbent utilities and other entities to participate in the planning and construction of new projects in our service area and regionally.


Changes in the Transmission Operating Agreement, the New England Transmission Tariff or legislative policy, or implementation of these new FERC planning rules, could adversely affect our transmission planning, our earnings and our prospects for growth.


Changes in regulatory or legislative policy or unfavorable outcomes in regulatory proceedings could jeopardize our full and/or timely recovery of costs incurred by our regulated distribution and generation businesses.


Under state law, our Regulated companies are entitled to charge rates that are sufficient to allow them an opportunity to recover their reasonable operating and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.  Each of these companies prepares and submits periodic rate filings with their respective state regulatory commissions for review and approval.  There is no assurance that these state commissions will approve the recovery of all such costs incurred by our Regulated companies, such as for construction, operation and maintenance, as well as a return on investment on their respective regulated assets.  The amount of costs incurred by the Regulated companies, coupled with increases in fuel and energy prices, could lead to consumer or regulatory resistance to the timely recovery of such costs, thereby adversely affecting our financial position, results of operations or cash flows.  


Additionally, state legislators may enact laws that significantly impact our Regulated companies' revenues, including by mandating electric or gas rate relief and/or by requiring surcharges to customer bills to support state programs not related to the utilities or energy policy.  Such increases could pressure overall rates to our customers and our routine requests to regulators for rate relief.


In addition, CL&P, NSTAR Electric and WMECO procure energy for a substantial portion of their customers' needs via requests for proposal on an annual, semi-annual or quarterly basis.  CL&P, NSTAR Electric and WMECO receive approval to recover the costs of these contracts from the PURA and DPU, respectively.  While both regulatory agencies have consistently approved the solicitation processes, results and recovery of costs, management cannot predict the outcome of future solicitation efforts or the regulatory proceedings related thereto.


PSNH meets most of its energy requirements through its own generation resources and fixed-price forward purchase contracts.  PSNH's remaining energy needs are met primarily through spot market purchases.  Unplanned forced outages of its generating plants could increase the level of energy purchases needed by PSNH and therefore increase the market risk associated with procuring the energy to meet its requirements.  PSNH recovers these costs through its ES rate, subject to a prudence review by the NHPUC.  We cannot predict the outcome of future regulatory proceedings related to recovery of these costs.


Our goodwill is valued and recorded at an amount that, if impaired and written down, could adversely affect our future operating results and total capitalization.


We have a significant amount of goodwill on our consolidated balance sheet.  The carrying value of goodwill represents the fair value of an acquired business in excess of identifiable assets and liabilities as of the acquisition date.  As of December 31, 2014, goodwill totaled $3.5 billion, of which $3.2 billion was attributable to the acquisition of NSTAR in April 2012.  Total goodwill represented approximately 35 percent of our $10 billion of shareholders' equity and approximately 12 percent of our total assets of $29.8 billion.  We test our goodwill balances for impairment on an annual basis or whenever events occur or circumstances change that would indicate a potential for impairment.  A determination that goodwill is deemed to be impaired would result in a non-cash charge that could materially adversely affect our results of operations and total capitalization.  The annual goodwill impairment test in 2014 resulted in a conclusion that goodwill is not impaired.  


Severe storms could cause significant damage to any of our facilities requiring extensive expenditures, the recovery for which is subject to approval by regulators.


Severe weather, such as ice and snow storms, hurricanes and other natural disasters, may cause outages and property damage, which may require us to incur additional costs that may not be recoverable from customers.  The cost of repairing damage to our operating subsidiaries' facilities and the potential disruption of their operations due to storms, natural disasters or other catastrophic events could be substantial, particularly as customers



17


demand better and quicker response times to outages.  If, upon review, any of our state regulatory authorities finds that our actions were imprudent, some of those restoration costs may not be recoverable from customers.  The inability to recover a significant amount of such costs could have an adverse effect on our financial position, results of operations and cash flows.


NU and its utility subsidiaries are exposed to significant reputational risks, which make them vulnerable to increased regulatory oversight or other sanctions.


Because utility companies, including our electric and natural gas utility subsidiaries, have large consumer customer bases, they are subject to adverse publicity focused on the reliability of their distribution services and the speed with which they are able to respond to electric outages, natural gas leaks and similar interruptions caused by storm damage or other unanticipated events.  Adverse publicity of this nature could harm the reputations of NU and its subsidiaries, and may make state legislatures, utility commissions and other regulatory authorities less likely to view NU and its subsidiaries in a favorable light, and may cause NU and its subsidiaries to be subject to less favorable legislative and regulatory outcomes or increased regulatory oversight.  Unfavorable regulatory outcomes can include more stringent laws and regulations governing our operations, such as reliability and customer service quality standards or vegetation management requirements, as well as fines, penalties or other sanctions or requirements.  The imposition of any of the foregoing could have a material adverse effect on our business, results of operations, cash flow and financial condition of NU and each of its utility subsidiaries.


Limits on our access to and increases in the cost of capital may adversely impact our ability to execute our business plan.


We use short-term debt and the long-term capital markets as a significant source of liquidity and funding for capital requirements not obtained from our operating cash flow.  If access to these sources of liquidity becomes constrained, our ability to implement our business strategy could be adversely affected.  In addition, higher interest rates would increase our cost of borrowing, which could adversely impact our results of operations.  A downgrade of our credit ratings or events beyond our control, such as a disruption in global capital and credit markets, could increase our cost of borrowing and cost of capital or restrict our ability to access the capital markets and negatively affect our ability to maintain and to expand our businesses.


Our counterparties may not meet their obligations to us or may elect to exercise their termination rights, which could adversely affect our earnings.


We are exposed to the risk that counterparties to various arrangements who owe us money, have contracted to supply us with energy, coal, or other commodities or services, or who work with us as strategic partners, including on significant capital projects, will not be able to perform their obligations, will terminate such arrangements or, with respect to our credit facilities, fail to honor their commitments.  Should any of these counterparties fail to perform their obligations or terminate such arrangements, we might be forced to replace the underlying commitment at higher market prices and/or have to delay the completion of, or cancel a capital project.  Should any lenders under our credit facilities fail to perform, the level of borrowing capacity under those arrangements could decrease.  In any such events, our financial position, results of operations, or cash flows could be adversely affected.


Judicial or regulatory proceedings or changes in regulatory or legislative policy could jeopardize full recovery of costs incurred by PSNH in constructing the Clean Air Project.


Pursuant to New Hampshire law, PSNH placed the Clean Air Project in service at its Merrimack Station.  PSNH's recovery of costs in constructing the project is subject to prudence review by the NHPUC.  A material prudence disallowance could adversely affect PSNH's financial position, results of operations or cash flows.  While we believe we have prudently incurred all expenditures to date, we cannot predict the outcome of any prudence reviews.  Our projected earnings and growth could be adversely affected were the NHPUC to deny recovery of some or all of PSNH's investment in the project.


The loss of key personnel or the inability to hire and retain qualified employees could have an adverse effect on our business, financial position and results of operations.


Our operations depend on the continued efforts of our employees.  Retaining key employees and maintaining the ability to attract new employees are important to both our operational and financial performance.  We cannot guarantee that any member of our management or any key employee at the NU parent or subsidiary level will continue to serve in any capacity for any particular period of time.  In addition, a significant portion of our workforce, including many workers with specialized skills maintaining and servicing the electrical infrastructure, will be eligible to retire over the next five to ten years.  Such highly skilled individuals cannot be quickly replaced due to the technically complex work they perform.  We have developed strategic workforce plans to identify key functions and proactively implement plans to assure a ready and qualified workforce, but cannot predict the impact of these plans on our ability to hire and retain key employees.


Market performance or changes in assumptions require us to make significant contributions to our pension and other postretirement benefit plans.


We provide a defined benefit pension plan and other postretirement benefits for a substantial number of employees, former employees and retirees.  Our future pension obligations, costs and liabilities are highly dependent on a variety of factors beyond our control.  These factors include estimated investment returns, interest rates, discount rates, health care cost trends, benefit changes, salary increases and the demographics of plan participants.  If our assumptions prove to be inaccurate, our future costs could increase significantly.  In 2014, NU made contributions to the Pension Plans totaling $171.6 million.  We expect to make contributions in 2015 totaling $155 million.  In addition, various factors, including underperformance of plan investments and changes in law or regulation, could increase the amount of contributions required to fund our pension plan in the future.  Additional large funding requirements, when combined with the financing requirements of our construction program, could impact the timing and amount of future equity and debt financings and negatively affect our financial position, results of operations or cash flows.  



18



Costs of compliance with environmental regulations, including climate change legislation, may increase and have an adverse effect on our business and results of operations.


Our subsidiaries' operations are subject to extensive federal, state and local environmental statutes, rules and regulations that govern, among other things, air emissions, water discharges and the management of hazardous and solid waste.  Compliance with these requirements requires us to incur significant costs relating to environmental monitoring, installation of pollution control equipment, emission fees, maintenance and upgrading of facilities, remediation and permitting.  The costs of compliance with existing legal requirements or legal requirements not yet adopted may increase in the future.  An increase in such costs, unless promptly recovered, could have an adverse impact on our business and our financial position, results of operations or cash flows.


In addition, global climate change issues have received an increased focus from federal and state governments, including EPA's proposed draft carbon pollution emission guidelines for existing utility generating units, which could potentially lead to additional rules and regulations that impact how we operate our business, both in terms of the power plants we own and operate as well as general utility operations.  Although we would expect that any costs of these rules and regulations would be recovered from customers, their impact on energy use by customers and the ultimate impact on our business would be dependent upon the specific rules and regulations adopted and cannot be determined at this time.  The impact of these additional costs to customers could lead to a further reduction in energy consumption resulting in a decline in electricity and gas sales in our service territories, which would have an adverse impact on our business and financial position, results of operations or cash flows.


Any failure by us to comply with environmental laws and regulations, even if due to factors beyond our control, or reinterpretations of existing requirements, could also increase costs.  Existing environmental laws and regulations may be revised or new laws and regulations seeking to protect the environment may be adopted or become applicable to us.  Revised or additional laws could result in significant additional expense and operating restrictions on our facilities or increased compliance costs, which may not be fully recoverable in distribution company rates.  The cost impact of any such laws, rules or regulations would be dependent upon the specific requirements adopted and cannot be determined at this time.  For further information, see Item 1, Business - Other Regulatory and Environmental Matters, included in this Annual Report on Form 10-K.


As a holding company with no revenue-generating operations, NU parent's liquidity is dependent on dividends from its subsidiaries, primarily the Regulated companies, its commercial paper program, and its ability to access the long-term debt and equity capital markets.


NU parent is a holding company and as such, has no revenue-generating operations of its own.  Its ability to meet its debt service obligations and to pay dividends on its common shares is largely dependent on the ability of its subsidiaries to pay dividends to or repay borrowings from NU parent, and/or NU parent's ability to access its commercial paper program or the long-term debt and equity capital markets.  Prior to funding NU parent, the Regulated companies have financial obligations that must be satisfied, including among others, their operating expenses, debt service, preferred dividends (in the case of CL&P and NSTAR Electric), and obligations to trade creditors.  Additionally, the Regulated companies could retain their free cash flow to fund their capital expenditures in lieu of receiving equity contributions from NU parent.  Should the Regulated companies not be able to pay dividends or repay funds due to NU parent, or if NU parent cannot access its commercial paper programs or the long-term debt and equity capital markets, NU parent's ability to pay interest, dividends and its own debt obligations would be restricted.


Item 1B.

Unresolved Staff Comments


We do not have any unresolved SEC staff comments.  




19



Item 2.

Properties

 

 

 

 

 

 

Transmission and Distribution System

 

 

 

 

 

 

 

 

 

 

As of December 31, 2014, NU and our electric operating subsidiaries owned the following:

 

 

 

 

 

 

 

 

Electric

 

Electric

 

NU

Distribution

 

Transmission

 

Number of substations owned

 513 

 

 63 

 

Transformer capacity (in kVa)

 40,853,000 

 

 17,117,000 

 

Overhead lines (distribution in pole miles and
    transmission in circuit miles)

 48,496 

 

 3,880 

 

Capacity range of overhead transmission lines (in kV)

N/A 

 

69 to 345

 

Underground lines (distribution in conduit bank miles and
    transmission in cable miles)

 16,770 

 

 408 

 

Capacity range of underground transmission lines (in kV)

 N/A 

 

69 to 345

 


 

 

 

CL&P

 

NSTAR Electric

 

PSNH

 

WMECO

 

 

 

Distribution

 

Transmission

 

Distribution

 

Transmission

 

Distribution

 

Transmission

 

Distribution

 

Transmission

Number of substations owned

 

 182 

 

 19 

 

 133 

 

 21 

 

 155 

 

 16 

 

 43 

 

 7 

Transformer capacity (in kVa)

 

 19,082,000 

 

 3,117,000 

 

 11,381,000 

 

 10,065,000 

 

 5,218,000 

 

 3,868,000 

 

 5,172,000 

 

 67,000 

Overhead lines (distribution in
    pole miles and transmission
    in circuit miles)

 

 18,376 

 

 1,630 

 

 14,338 

 

 742 

 

 11,987 

 

 1,027 

 

 3,795 

 

 481 

Capacity range of overhead
    transmission lines (in kV)

 

 N/A 

 

69 to 345

 

N/A 

 

115 to 345

 

 N/A 

 

115 to 345

 

 N/A 

 

69 to 345

Underground lines (distribution
    in conduit bank miles and
    transmission in cable miles)

 

 1,186 

 

 137 

 

 13,496 

 

 260 

 

 1,795 

 

 1 

 

 293 

 

 10 

Capacity range of underground
    transmission lines (in kV)

 

N/A 

 

69 to 345

 

N/A 

 

115 to 345

 

N/A 

 

 115 

 

N/A 

 

 115 


 

 

 

 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

 

 

 

NU

 

CL&P

 

 Electric

 

PSNH

 

WMECO

Underground and overhead line transformers in service

 

 622,104 

 

 

 287,641 

 

 

 123,997 

 

 

 167,703 

 

 

 42,763 

 

Aggregate capacity (in kVa)

 

 35,196,926 

 

 

 15,118,641 

 

 

 10,828,218 

 

 

 7,122,928 

 

 

 2,127,139 

 


Electric Generating Plants


As of December 31, 2014, PSNH owned the following electric generating plants:  


Type of Plant

 

Number
of Units

 

Year
Installed

 

Claimed Capability*
(kilowatts)

Steam Plants

 

 

1952-74

 

 935,343 

Hydro

 

20 

 

1901-83

 

 58,115 

Internal Combustion

 

 

1968-70

 

 101,869 

Biomass

 

 

2006

 

 42,594 

Total PSNH Generating Plant

 

31 

 

 

 

 1,137,921 


*

Claimed capability represents winter ratings as of December 31, 2014.  The combined nameplate capacity of the generating plants is approximately 1,200 MW.


As of December 31, 2014, WMECO owned the following electric generating plants:  


Type of Plant

 

 

Number
of Sites

 

Year
Installed

 

Claimed Capability**
(kilowatts)

Solar Fixed Tilt, Photovoltaic

 

        3

 

2010-14

 

8,000


** Claimed capability represents the direct current nameplate capacity of the plant.


CL&P and NSTAR Electric do not own any electric generating plants.


Natural Gas Distribution System


As of December 31, 2014, Yankee Gas owned 28 active gate stations, 201 district regulator stations, and approximately 3,300 miles of natural gas main pipeline.  Yankee Gas also owns a liquefaction and vaporization plant and above ground storage tank with a storage capacity equivalent of 1.2 Bcf of natural gas in Waterbury, Connecticut.


As of December 31, 2014, NSTAR Gas owned 20 active gate stations, 162 district regulator stations, and approximately 3,230 miles of natural gas main pipeline.  Hopkinton, another subsidiary of NU, owns a satellite vaporization plant and above ground storage tanks in Acushnet, MA.  In



20


addition, Hopkinton owns a liquefaction and vaporization plant with above ground storage tanks in Hopkinton, MA.  Combined, the two plants' tanks have an aggregate storage capacity equivalent to 3.5 Bcf of natural gas that is provided to NSTAR Gas under contract.


Franchises


CL&P  Subject to the power of alteration, amendment or repeal by the General Assembly of Connecticut and subject to certain approvals, permits and consents of public authority and others prescribed by statute, CL&P has, subject to certain exceptions not deemed material, valid franchises free from burdensome restrictions to provide electric transmission and distribution services in the respective areas in which it is now supplying such service.


In addition to the right to provide electric transmission and distribution services as set forth above, the franchises of CL&P include, among others, limited rights and powers, as set forth under Connecticut law and the special acts of the General Assembly constituting its charter, to manufacture, generate, purchase and/or sell electricity at retail, including to provide Standard Service, Supplier of Last Resort service and backup service, to sell electricity at wholesale and to erect and maintain certain facilities on public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. The franchises of CL&P include the power of eminent domain.  Connecticut law prohibits an electric distribution company from owning or operating generation assets.  However, under "An Act Concerning Energy Independence," enacted in 2005, CL&P is permitted to own up to 200 MW of peaking facilities if the PURA determines that such facilities will be more cost effective than other options for mitigating FMCC and Locational Installed Capacity (LICAP) costs.  In addition, under "An Act Concerning Electricity and Energy Efficiency," enacted in 2007, an electric distribution company, such as CL&P, is permitted to purchase an existing electric generating plant located in Connecticut that is offered for sale, subject to prior approval from the PURA and a determination by the PURA that such purchase is in the public interest.  Finally, Connecticut law also allows CL&P to submit a proposal to the DEEP to build, own or operate one or more generation facilities up to 10 MWs using Class I renewable energy.


NSTAR Electric and NSTAR Gas  Through their charters, which are unlimited in time, NSTAR Electric and NSTAR Gas have the right to engage in the business of delivering and selling electricity and natural gas within their respective service territories, and have powers incidental thereto and are entitled to all the rights and privileges of and subject to the duties imposed upon electric and natural gas companies under Massachusetts laws.  The locations in public ways for electric transmission and distribution lines and natural gas distribution pipelines are obtained from municipal and other state authorities who, in granting these locations, act as agents for the state. In some cases the actions of these authorities are subject to appeal to the DPU.  The rights to these locations are not limited in time and are subject to the action of these authorities and the legislature.  Under Massachusetts law, with the exception of municipal-owned utilities, no other entity may provide electric or natural gas delivery service to retail customers within NSTAR's service territory without the written consent of NSTAR Electric and/or NSTAR Gas.  This consent must be filed with the DPU and the municipality so affected.


The Massachusetts restructuring legislation defines service territories as those territories actually served on July 1, 1997 and following municipal boundaries to the extent possible.  The restructuring legislation further provides that until terminated by law or otherwise, distribution companies shall have the exclusive obligation to serve all retail customers within their service territories and no other person shall provide distribution service within such service territories without the written consent of such distribution companies.  Pursuant to the Massachusetts restructuring legislation, the DPU (then, the Department of Telecommunications and Energy) was required to define service territories for each distribution company, including NSTAR Electric.  The DPU subsequently determined that there were advantages to the exclusivity of service territories and issued a report to the Massachusetts Legislature recommending against, in this regard, any changes to the restructuring legislation.


PSNH  The NHPUC, pursuant to statutory requirements, has issued orders granting PSNH exclusive franchises to distribute electricity in the respective areas in which it is now supplying such service.  


In addition to the right to distribute electricity as set forth above, the franchises of PSNH include, among others, rights and powers to manufacture, generate, purchase, and transmit electricity, to sell electricity at wholesale to other utility companies and municipalities and to erect and maintain certain facilities on certain public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law.  PSNH's status as a public utility gives it the ability to petition the NHPUC for the right to exercise eminent domain for its transmission and distribution services in appropriate circumstances.  


PSNH is also subject to certain regulatory oversight by the Maine Public Utilities Commission and the Vermont Public Service Board.


WMECO  WMECO is authorized by its charter to conduct its electric business in the territories served by it, and has locations in the public highways for transmission and distribution lines.  Such locations are granted pursuant to the laws of Massachusetts by the Department of Public Works of Massachusetts or local municipal authorities and are of unlimited duration, but the rights thereby granted are not vested.  Such locations are for specific lines only and for extensions of lines in public highways.  Further similar locations must be obtained from the Department of Public Works of Massachusetts or the local municipal authorities.  In addition, WMECO has been granted easements for its lines in the Massachusetts Turnpike by the Massachusetts Turnpike Authority and pursuant to state laws, has the power of eminent domain.  


The Massachusetts restructuring legislation applicable to NSTAR Electric (described above) is also applicable to WMECO.


Yankee Gas  Yankee Gas holds valid franchises to sell natural gas in the areas in which Yankee Gas supplies natural gas service, which it acquired either directly or from its predecessors in interest.  Generally, Yankee Gas holds franchises to serve customers in areas designated by those franchises as well as in most other areas throughout Connecticut so long as those areas are not occupied and served by another natural gas utility under a valid franchise of its own or are not subject to an exclusive franchise of another natural gas utility.  Yankee Gas' franchises are perpetual but remain subject to the power of alteration, amendment or repeal by the General Assembly of the State of Connecticut, the power of revocation by the PURA and certain approvals, permits and consents of public authorities and others prescribed by statute.  Generally, Yankee Gas' franchises include, among other rights and powers, the right and power to manufacture, generate, purchase, transmit and distribute natural gas and to erect and maintain certain



21


facilities on public highways and grounds, and the right of eminent domain, all subject to such consents and approvals of public authorities and others as may be required by law.


Item 3.

Legal Proceedings


1.

Yankee Companies v. U.S. Department of Energy


DOE Phase I Damages - In 1998, the Yankee Companies (CYAPC, YAEC and MYAPC) filed separate complaints against the DOE in the Court of Federal Claims seeking monetary damages resulting from the DOE's failure to begin accepting spent nuclear fuel for disposal by January 31, 1998 pursuant to the terms of the 1983 spent fuel and high level waste disposal contracts between the Yankee Companies and the DOE (DOE Phase I Damages).  Phase I covered damages for the period 1998 through 2002.  Following multiple appeals and cross-appeals in December 2012, the judgment awarding CYAPC $39.6 million, YAEC $38.3 million and MYAPC $81.7 million became final.


In January 2013, the proceeds from the DOE Phase I Damages Claim were received by the Yankee Companies and transferred to each Yankee Company's respective decommissioning trust.  


In June 2013, FERC approved CYAPC, YAEC and MYAPC to reduce rates in their wholesale power contracts through the application of the DOE proceeds for the benefit of customers.  Changes to the terms of the wholesale power contracts became effective on July 1, 2013.  In accordance with the FERC order, CL&P, NSTAR Electric, PSNH and WMECO began receiving the benefit of the DOE proceeds, and the benefits have been passed on to customers.


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.


DOE Phase II Damages - In December 2007, the Yankee Companies each filed subsequent lawsuits against the DOE seeking recovery of actual damages incurred related to the alleged failure of the DOE to provide for a permanent facility to store spent nuclear fuel generated in years 2001 through 2008 for CYAPC and YAEC and from 2002 through 2008 for MYAPC (DOE Phase II Damages).  In November 2013, the court issued a final judgment awarding CYAPC $126.3 million, YAEC $73.3 million, and MYAPC $35.8 million.  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.


In March and April 2014, CYAPC, YAEC and MYAPC received payment of $126.3 million, $73.3 million and $35.8 million, respectively, of the DOE Phase II Damages proceeds and 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.  Refunds to CL&P's, NSTAR Electric's, PSNH's and WMECO's customers for these DOE proceeds began in the third quarter of 2014.


DOE Phase III Damages - In August 2013, the Yankee Companies each filed subsequent lawsuits against the DOE seeking recovery of actual damages incurred in the years 2009 through 2012.  The presiding judge issued a Pre-Trial Scheduling Order on September 3, 2014 that set the case for trial from June 30 to July 2, 2015.  The Order also established January 5, 2015 for the close of fact discovery and March 30, 2015 as the close of expert discovery.  Expert discovery is ongoing.


2.

Conservation Law Foundation v. PSNH


On July 21, 2011, the Conservation Law Foundation (CLF) filed a citizens suit under the provisions of the federal Clean Air Act against PSNH alleging permitting violations at the company's Merrimack generating station. The suit alleges that PSNH failed to have proper permits for replacement of the Unit 2 turbine at Merrimack, installation of activated carbon injection equipment for the unit, and violated a permit condition concerning operation of the electrostatic precipitators at the station. On September 27, 2012, the federal court dismissed portions of CLF's suit pertaining to the installation of activated carbon injection and the electrostatic precipitators.  CLF filed an amended complaint on May 28, 2013, related to routine maintenance of the boiler performed in 2008 and 2009.  The suit seeks injunctive relief, civil penalties, and costs.  CLF has pursued similar claims before the NHPUC, the N.H. Air Resources Council, and the N.H. Site Evaluation Committee, all of which have been denied.  PSNH believes this suit is without merit and intends to defend it vigorously.  The deadline for summary judgment is November 2015.  Trial is scheduled for the spring of 2016.


3.

Other Legal Proceedings


For further discussion of legal proceedings, see Item 1, Business:  "- Electric Distribution Segment," "- Electric Transmission Segment," and "- Natural Gas Distribution Segment" for information about various state regulatory and rate proceedings, civil lawsuits related thereto, and information about proceedings relating to power, transmission and pricing issues; "- Nuclear Fuel Storage" for information related to high-level nuclear waste; and "- Other Regulatory and Environmental Matters" for information about proceedings involving surface water and air quality requirements, toxic substances and hazardous waste, electric and magnetic fields, licensing of hydroelectric projects, and other matters. In addition, see Item 1A, Risk Factors, for general information about several significant risks.




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Item 4.

Mine Safety Disclosures


Not applicable.


EXECUTIVE OFFICERS OF THE REGISTRANT


The following table sets forth the executive officers of NU as of February 18, 2015.  All of the Company's officers serve terms of one year and until their successors are elected and qualified:


Name

 

Age

 

Title

Jay S. Buth

 

45

 

Vice President, Controller and Chief Accounting Officer.

Gregory B. Butler

 

57

 

Senior Vice President and General Counsel.

Christine M. Carmody*

 

52

 

Senior Vice President-Human Resources of NUSCO.

James J. Judge

 

59

 

Executive Vice President and Chief Financial Officer.

Thomas J. May

 

67

 

Chairman of the Board, President and Chief Executive Officer.

David R. McHale

 

54

 

Executive Vice President and Chief Administrative Officer.

Joseph R. Nolan, Jr.*

 

51

 

Senior Vice President-Corporate Relations of NUSCO.

Leon J. Olivier

 

66

 

Executive Vice President-Enterprise Energy Strategy and Business Development.

Werner J. Schweiger

 

55

 

Executive Vice President and Chief Operating Officer.


* Deemed an executive officer of NU pursuant to Rule 3b-7 under the Securities Exchange Act of 1934.


Jay S. Buth.  Mr. Buth has served as Vice President, Controller and Chief Accounting Officer of NU, CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO, Yankee Gas and NUSCO since April 10, 2012.  Previously, Mr. Buth served as Vice President-Accounting and Controller of NU, CL&P, PSNH, WMECO, Yankee Gas and NUSCO from June 2009 until April 10, 2012.  From June 2006 through January 2009, Mr. Buth served as the Vice President and Controller for New Jersey Resources Corporation, an energy services holding company that provides natural gas and wholesale energy services, including transportation, distribution and asset management.


Gregory B. Butler.  Mr. Butler has served as Senior Vice President and General Counsel of NU since May 1, 2014, of NSTAR Electric, and NSTAR Gas since April 10, 2012, and of CL&P, PSNH, WMECO, Yankee Gas and NUSCO since March 9, 2006.  Mr. Butler has served as a Director of NSTAR Electric and NSTAR Gas since April 10, 2012, of NUSCO since November 27, 2012, and of CL&P, PSNH, WMECO and Yankee Gas since April 22, 2009.  Mr. Butler previously served as Senior Vice President, General Counsel and Secretary of NU from April 10, 2012 until May 1, 2014, and as Senior Vice President and General Counsel of NU from December 1, 2005 to April 10, 2012.  He has served as a Director of Eversource Energy Foundation, Inc. since December 1, 2002.


Christine M. Carmody.  Ms. Carmody has served as Senior Vice President-Human Resources of NUSCO since April 10, 2012 and as a Director of NUSCO since November 27, 2012.  Ms. Carmody previously served as Senior Vice President-Human Resources of CL&P, PSNH, WMECO and Yankee Gas from November 27, 2012 to September 29, 2014, and of NSTAR Electric and NSTAR Gas from August 1, 2008 to September 29, 2014, and as a Director of CL&P, PSNH, WMECO and Yankee Gas from April 10, 2012 to September 29, 2014 and of NSTAR Electric and NSTAR Gas from November 27, 2012 to September 29, 2014.  Previously, Ms. Carmody served as Vice President-Organizational Effectiveness of NSTAR, NSTAR Electric and NSTAR Gas from June 2006 to August 2008.  Ms. Carmody has served as a Director of Eversource Energy Foundation, Inc. since April 10, 2012.  She has served as a Trustee of the NSTAR Foundation since August 1, 2008.


James J. Judge.  Mr. Judge has served as Executive Vice President and Chief Financial Officer of NU, CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO, Yankee Gas and NUSCO and as a Director of CL&P, PSNH, WMECO, Yankee Gas and NUSCO since April 10, 2012 and of NSTAR Electric and NSTAR Gas since September 27, 1999.  Previously, Mr. Judge served as Senior Vice President and Chief Financial Officer of NSTAR, NSTAR Electric and NSTAR Gas from 1999 until April 2012.  Mr. Judge has served as Treasurer and as a Director of Eversource Energy Foundation, Inc. since April 10, 2012.  He has served as a Trustee of the NSTAR Foundation since December 12, 1995.  


Thomas J. May.  Mr. May has served as Chairman of the Board of NU since October 10, 2013, and as President and Chief Executive Officer and as a Trustee of NU; as Chairman and a Director of CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO and Yankee Gas; and as Chairman, President and Chief Executive Officer and a Director of NUSCO since April 10, 2012.  Mr. May has served as a Director of NSTAR Electric and NSTAR Gas since September 27, 1999.  Mr. May previously served as Chairman, President and Chief Executive Officer and a Trustee of NSTAR, and as Chairman, President and Chief Executive Officer of NSTAR Electric and NSTAR Gas until April 10, 2012.  He served as Chairman, Chief Executive Officer and a Trustee since NSTAR was formed in 1999, and was elected President in 2002.  Mr. May has served as Chairman of the Board of Eversource Energy Foundation, Inc. since October 15, 2013, and as a Director of Eversource Energy Foundation, Inc. since April 10, 2012.  He previously served as President of Eversource Energy Foundation, Inc. from October 15, 2013 to September 29, 2014.  He has served as a Trustee of the NSTAR Foundation since August 18, 1987.  


David R. McHale.  Mr. McHale has served as Executive Vice President and Chief Administrative Officer of NU and NUSCO since April 10, 2012 and as a Director of NUSCO since January 1, 2005.  Mr. McHale previously served as Executive Vice President and Chief Administrative Officer of CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO and Yankee Gas from April 10, 2012 to September 29, 2014 and as a Director of NSTAR Electric and NSTAR Gas from November 27, 2012 to September 29, 2014, of PSNH, WMECO and Yankee Gas from January 1, 2005 to September 29, 2014, and of CL&P from January 15, 2007 to September 29, 2014.  Previously, Mr. McHale served as Executive Vice President and Chief Financial Officer of NU, CL&P, PSNH, WMECO, Yankee Gas and NUSCO from January 2009 to April 2012, and as Senior Vice President and Chief Financial Officer of NU, CL&P, PSNH, WMECO, Yankee Gas and NUSCO from January 2005 to December 2008.  He has served as a Director of Eversource Energy Foundation, Inc. since January 1, 2005.  Mr. McHale has served as a Trustee of the NSTAR Foundation since April 10, 2012.  



23



Joseph R. Nolan, Jr.  Mr. Nolan has served as Senior Vice President-Corporate Relations of NUSCO since April 10, 2012 and as a Director of NUSCO since November 27, 2012.  Mr. Nolan previously served as Senior Vice President-Corporate Relations of NSTAR Electric and NSTAR Gas from April 10, 2012 to September 29, 2014, and of CL&P, PSNH, WMECO and Yankee Gas from November 27, 2012 to September 29, 2014, as a Director of CL&P, PSNH, WMECO and Yankee Gas from April 10, 2012 to September 29, 2014 and of NSTAR Electric and NSTAR Gas from November 27, 2012 to September 29, 2014.  Previously, Mr. Nolan served as Senior Vice President-Customer & Corporate Relations of NSTAR, NSTAR Electric and NSTAR Gas from 2006 until April 10, 2012.  Mr. Nolan has served as a Director of Eversource Energy Foundation, Inc. since April 10, 2012, and has served as Executive Director of Eversource Energy Foundation, Inc. since October 15, 2013.  He has served as a Trustee of the NSTAR Foundation since October 1, 2000.


Leon J. Olivier.  Mr. Olivier has served as Executive Vice President-Enterprise Energy Strategy and Business Development of NU since September 2, 2014 and as a Director of NUSCO since January 17, 2005.  Mr. Olivier previously served as Executive Vice President and Chief Operating Officer of NU and NUSCO from May 13, 2008 until September 2, 2014, and as Chief Executive Officer of NSTAR Electric and NSTAR Gas from April 10, 2012 until August 11, 2014, of CL&P, PSNH, WMECO and Yankee Gas from January 15, 2007 to September 29, 2014, and of CL&P from September 10, 2001 to September 29, 2014, and as a Director of NSTAR Electric and NSTAR Gas from November 27, 2012 to September 29, 2014, of PSNH, WMECO and Yankee Gas from January 17, 2005 to September 29, 2014, and of CL&P from September 10, 2001 to September 29, 2014.   Previously, Mr. Olivier served as Executive Vice President-Operations of NU from February 13, 2007 to May 12, 2008.  He has served as a Director of Eversource Energy Foundation, Inc. since April 1, 2006.  Mr. Olivier has served as a Trustee of the NSTAR Foundation since April 10, 2012.  


Werner J. Schweiger.  Mr. Schweiger has served as Executive Vice President and Chief Operating Officer of NU since September 2, 2014 and of NUSCO since August 11, 2014, and as Chief Executive Officer of CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO and Yankee Gas since August 11, 2014, and as a Director of NUSCO, NSTAR Gas and Yankee Gas since September 29, 2014 and of CL&P, PSNH, NSTAR Electric and WMECO since May 28, 2013.  He previously served as President-Electric Distribution of NUSCO from January 16, 2013 until August 11, 2014 and as President of NSTAR Electric from April 10, 2012 until January 16, 2013 and as a Director of NSTAR Electric from November 27, 2012 to January 16, 2013.  From February 27, 2002 until April 10, 2012, Mr. Schweiger was Senior Vice President-Operations of NSTAR Electric and NSTAR Gas.  Mr. Schweiger has served as a Director of Eversource Energy Foundation, Inc. since September 29, 2014.  He has served as a Trustee of the NSTAR Foundation since April 25, 2002.


PART II


Item 5.

Market for the Registrants' Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities


(a)

Market Information and (c) Dividends


NU.  Our common shares are listed on the New York Stock Exchange.  Effective February 19, 2015, the ticker symbol is "ES."  The high and low sales prices of our common shares and the dividends declared, for the past two years, by quarter, are shown below.


Year

 

Quarter

 

High

 

Low

 

Dividends
Declared

2014

 

First

 

$

45.69 

 

$

41.28 

 

$

0.393 

 

 

Second

 

 

47.60 

 

 

44.28 

 

 

0.393 

 

 

Third

 

 

47.37 

 

 

41.92 

 

 

0.393 

 

 

Fourth

 

 

56.66 

 

 

44.37 

 

 

0.393 

 

 

 

 

 

 

 

 

 

 

 

 

2013

 

First

 

$

 43.49 

 

$

 38.60 

 

$

 0.368 

 

 

Second

 

 

 45.66 

 

 

 39.35 

 

 

 0.368 

 

 

Third

 

 

 45.13 

 

 

 40.01 

 

 

 0.368 

 

 

Fourth

 

 

 43.75 

 

 

 40.60 

 

 

 0.368 


Information with respect to dividend restrictions for us, CL&P, NSTAR Electric, PSNH, and WMECO is contained in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, under the caption "Liquidity" and Item 8, Financial Statements and Supplementary Data, in the Combined Notes to Consolidated Financial Statements, within this Annual Report on Form 10-K.   


There is no established public trading market for the common stock of CL&P, NSTAR Electric, PSNH and WMECO.  All of the common stock of CL&P, NSTAR Electric, PSNH and WMECO is held solely by NU.




24


Common stock dividends approved and paid to NU during the year were as follows:


 

For the Years Ended December 31,

(Millions of Dollars)

2014

 

2013

CL&P

$

171.2 

 

$

152.0 

NSTAR Electric

 

253.0 

 

 

56.0 

PSNH

 

66.0 

 

 

68.0 

WMECO

 

   60.0 

 

 

40.0 


(b)

Holders


As of January 31, 2015, there were 44,860 registered common shareholders of our company on record.  As of the same date, there were a total of 317,203,765 common shares issued.


(d)

Securities Authorized for Issuance Under Equity Compensation Plans


For information regarding securities authorized for issuance under equity compensation plans, see Item 12, Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, included in this Annual Report on Form 10-K.


(e)

Performance Graph


The performance graph below illustrates a five-year comparison of cumulative total returns based on an initial investment of $100 in 2009 in Northeast Utilities common stock, as compared with the S&P 500 Stock Index and the EEI Index for the period 2010 through 2014, assuming all dividends are reinvested.


[f2014form10kedgar003.gif]





25


Purchases of Equity Securities by the Issuer and Affiliated Purchasers


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)

October 1 - October 31, 2014

 

 -   

 

$

 -   

 -   

 -   

November 1 - November 30, 2014

 

 -   

 

 

 -   

 -   

 -   

December 1 - December 31, 2014

 

 62,976 

 

 

50.91 

 -   

 -   

Total

 

 62,976 

 

$

50.91 

 -   

 -   


Item 6.

Selected Consolidated Financial Data

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NU Selected Consolidated Financial Data (Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Thousands of Dollars, except percentages and

  common share information)

2014 

 

2013 

 

2012 (a)

 

2011 

 

2010 

 

Balance Sheet Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property, Plant and Equipment, Net

$

 18,647,041 

 

$

 17,576,186 

 

$

 16,605,010 

 

$

 10,403,065 

 

$

9,567,726 

 

 

Total Assets

 

 29,777,975 

 

 

 27,795,537 

 

 

 28,302,824 

 

 

 15,647,066 

 

 

14,472,601 

 

 

Total Capitalization (b) (c)

 

 18,983,983 

 

 

 18,077,274 

 

 

 17,356,112 

 

 

 9,078,321 

 

 

8,627,985 

 

 

Obligations Under Capital Leases (b)

 

 9,434 

 

 

 10,744 

 

 

 11,071 

 

 

 12,358 

 

 

12,236 

 

Income Statement Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

$

 7,741,856 

 

$

 7,301,204 

 

$

 6,273,787 

 

$

 4,465,657 

 

$

4,898,167 

 

 

Net Income

 

 827,065 

 

 

 793,689 

 

 

 533,077 

 

 

 400,513 

 

 

394,107 

 

 

Net Income Attributable to Noncontrolling Interests

 

 7,519 

 

 

 7,682 

 

 

 7,132 

 

 

 5,820 

 

 

6,158 

 

 

Net Income Attributable to Controlling Interest

$

 819,546 

 

$

 786,007 

 

$

 525,945 

 

$

 394,693 

 

$

 387,949 

 

Common Share Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Income Attributable to Controlling Interest:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic Earnings Per Common Share

$

 2.59 

 

$

 2.49 

 

$

 1.90 

 

$

 2.22 

 

$

 2.20 

 

 

 

Diluted Earnings Per Common Share

$

 2.58 

 

$

 2.49 

 

$

 1.89 

 

$

 2.22 

 

$

2.19 

 

 

Weighted Average Common Shares Outstanding:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

 316,136,748 

 

 

 315,311,387 

 

 

 277,209,819 

 

 

177,410,167 

 

 

176,636,086 

 

 

 

Diluted

 

 317,417,414 

 

 

 316,211,160 

 

 

 277,993,631 

 

 

177,804,568 

 

 

176,885,387 

 

 

Dividends Declared Per Common Share

$

 1.57 

 

$

 1.47 

 

$

 1.32 

 

$

 1.10 

 

$

1.03 

 

 

Market Price - Closing (high) (d)

$

56.15 

 

$

45.33 

 

$

40.57 

 

$

36.31 

 

$

32.05 

 

 

Market Price - Closing (low) (d)

$

41.52 

 

$

38.67 

 

$

33.53 

 

$

30.46 

 

$

24.78 

 

 

Market Price - Closing (end of year) (d)

$

53.52 

 

$

42.39 

 

$

39.08 

 

$

36.07 

 

$

31.88 

 

 

Book Value Per Common Share (end of year)

$

31.47 

 

$

30.49 

 

$

29.41 

 

$

22.65 

 

$

21.60 

 

 

Tangible Book Value Per Common Share (end of year) (e)

$

20.37 

 

$

19.32 

 

$

18.21 

 

$

21.03 

 

$

19.97 

 

 

Rate of Return Earned on Average Common Equity (%) (f)

 

8.4 

 

 

8.3 

 

 

7.9 

 

 

 10.1 

 

 

 10.7 

 

 

Market-to-Book Ratio (end of year) (g)

 

1.7 

 

 

1.4 

 

 

1.3 

 

 

 1.6 

 

 

 1.5 

 

Capitalization:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Equity

 

 53 

%

 

 53 

%

 

53 

%

 

44 

%

 

44 

%

 

Preferred Stock, not subject to mandatory redemption

 

 1 

 

 

 1 

 

 

 

 

 

 

 

 

Long-Term Debt (b) (c)

 

 46 

 

 

 46 

 

 

46 

 

 

55 

 

 

55 

 

 

 

 

 

 

 

100 

%

 

100 

%

 

100 

%

 

100 

%

 

100 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

The 2012 results include the operations of NSTAR beginning April 10, 2012.

 

 

(b)

Includes portions due within one year.

 

 

(c)

Excludes RRBs.

 

 

(d)

Market price information reflects closing prices as reflected by the New York Stock Exchange.  

 

 

(e)

Common Shareholders' Equity adjusted for goodwill and intangibles divided by total common shares outstanding.

 

 

(f)

Net Income Attributable to Controlling Interest divided by average Common Shareholders' Equity.  

 

 

(g)

The closing market price divided by the book value per share.

 

 

 

 

 

 

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CL&P Selected Financial Data (Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Thousands of Dollars)

2014 

 

2013 

 

2012 

 

2011 

 

2010 

 

Operating Revenues

$

 2,692,582 

 

$

 2,442,341 

 

$

 2,407,449 

 

$

 2,548,387 

 

$

 2,999,102 

 

Net Income

 

 287,754 

 

 

 279,412 

 

 

 209,725 

 

 

 250,164 

 

 

 244,143 

 

Cash Dividends on Common Stock

 

 171,200 

 

 

 151,999 

 

 

 100,486 

 

 

 243,218 

 

 

 217,691 

 

Property, Plant and Equipment, Net

 

 6,809,664 

 

 

 6,451,259 

 

 

 6,152,959 

 

 

 5,827,384 

 

 

 5,586,504 

 

Total Assets

 

 9,360,108 

 

 

 8,980,502 

 

 

 9,142,088 

 

 

 8,791,396 

 

 

 8,255,192 

 

Long-Term Debt (a)

 

 2,841,951 

 

 

 2,741,208 

 

 

 2,862,790 

 

 

 2,583,753 

 

 

 2,583,102 

 

Preferred Stock Not Subject to Mandatory Redemption

 

 116,200 

 

 

 116,200 

 

 

 116,200 

 

 

 116,200 

 

 

 116,200 

 

Obligations Under Capital Leases (a)

 

 8,439 

 

 

 9,309 

 

 

 9,960 

 

 

 10,715 

 

 

 10,613 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

Includes portions due within one year.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

See the Combined Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for a description of any accounting changes materially affecting the comparability of the information reflected in the tables above.

 




26






NU Selected Consolidated Sales Statistics

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014 

 

 

2013 

 

 

2012 (a)

 

 

2011 

 

 

2010 

Revenues:  (Thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

$

 3,288,313 

 

$

 3,073,181 

 

$

 2,731,951 

 

$

 2,091,270 

 

$

2,336,078 

Commercial

 

 2,471,440 

 

 

 2,387,535 

 

 

 1,604,661 

 

 

 1,236,374 

 

 

1,346,228 

Industrial

 

 348,698 

 

 

 339,917 

 

 

 753,974 

 

 

 252,878 

 

 

268,598 

Wholesale

 

 447,899 

 

 

 486,515 

 

 

 357,223 

 

 

 350,413 

 

 

506,475 

Other and Eliminations

 

 97,090 

 

 

 56,547 

 

 

 130,137 

 

 

 47,485 

 

 

(29,878)

Total Electric

 

 6,653,440 

 

 

 6,343,695 

 

 

 5,577,946 

 

 

 3,978,420 

 

 

4,427,501 

Natural Gas

 

 1,002,880 

 

 

 855,601 

 

 

 572,857 

 

 

 430,799 

 

 

434,277 

Total - Regulated Companies

 

 7,656,320 

 

 

 7,199,296 

 

 

 6,150,803 

 

 

 4,409,219 

 

 

4,861,778 

Other and Eliminations

 

 85,536 

 

 

 101,908 

 

 

 122,984 

 

 

 56,438 

 

 

36,389 

Total

$

 7,741,856 

 

$

 7,301,204 

 

$

 6,273,787 

 

$

 4,465,657 

 

$

 4,898,167 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Regulated Companies - Sales:  (GWh)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

 

 21,317 

 

 

 21,896 

 

 

 19,719 

 

 

 14,766 

 

 

14,913 

Commercial

 

 27,449 

 

 

 27,787 

 

 

 24,537 

 

 

 14,628 

 

 

14,836 

Industrial

 

 5,676 

 

 

 5,648 

 

 

 5,462 

 

 

 4,418 

 

 

4,481 

Wholesale

 

 3,018 

 

 

 855 

 

 

 2,154 

 

 

 1,020 

 

 

3,423 

Total

 

 57,460 

 

 

 56,186 

 

 

 51,872 

 

 

 34,832 

 

 

37,653 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Regulated Companies - Customers:  (Average)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

 

 2,734,047 

 

 

 2,718,727 

 

 

 2,711,407 

 

 

 1,710,342 

 

 

1,704,197 

Commercial

 

 373,511 

 

 

 371,897 

 

 

 370,389 

 

 

 199,240 

 

 

198,558 

Industrial

 

 8,016 

 

 

 8,109 

 

 

 8,279 

 

 

 7,083 

 

 

7,150 

Total Electric

 

 3,115,574 

 

 

 3,098,733 

 

 

 3,090,075 

 

 

 1,916,665 

 

 

1,909,905 

Natural Gas

 

 499,186 

 

 

 493,563 

 

 

 483,770 

 

 

 207,753 

 

 

205,885 

Total

 

 3,614,760 

 

 

 3,592,296 

 

 

 3,573,845 

 

 

 2,124,418 

 

 

2,115,790 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a) The 2012 results include the operations of NSTAR beginning April 10, 2012.


CL&P Selected Sales Statistics

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014 

 

 

2013 

 

 

2012 

 

 

2011 

 

 

2010 

Revenues:  (Thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

$

 1,474,181 

 

$

 1,294,160 

 

$

 1,263,845 

 

$

 1,345,290 

 

$

1,597,754 

Commercial

 

 879,343 

 

 

 780,585 

 

 

 732,620 

 

 

 758,145 

 

 

853,956 

Industrial

 

 149,220 

 

 

 129,557 

 

 

 126,165 

 

 

 126,783 

 

 

144,463 

Wholesale

 

 146,787 

 

 

 219,367 

 

 

 214,807 

 

 

 278,751 

 

 

441,660 

Other

 

 43,051 

 

 

 18,672 

 

 

 70,012 

 

 

 39,418 

 

 

(38,731)

Total

$

 2,692,582 

 

$

 2,442,341 

 

$

 2,407,449 

 

$

 2,548,387 

 

$

2,999,102 

Sales:  (GWh)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

 

 10,026 

 

 

 10,314 

 

 

 9,978 

 

 

 10,092 

 

 

10,196 

Commercial

 

 9,643 

 

 

 9,770 

 

 

 9,705 

 

 

 9,809 

 

 

10,002 

Industrial

 

 2,377 

 

 

 2,320 

 

 

 2,426 

 

 

 2,414 

 

 

2,467 

Wholesale

 

 736 

 

 

 851 

 

 

 1,155 

 

 

 1,592 

 

 

3,040 

Total

 

 22,782 

 

 

 23,255 

 

 

 23,264 

 

 

 23,907 

 

 

25,705 

Customers:  (Average)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

 

 1,111,467 

 

 

 1,105,417 

 

 

 1,103,397 

 

 

 1,100,740 

 

 

1,096,576 

Commercial

 

 109,093 

 

 

 108,735 

 

 

 108,589 

 

 

 108,235 

 

 

107,532 

Industrial

 

 3,213 

 

 

 3,247 

 

 

 3,301 

 

 

 3,331 

 

 

3,359 

Total

 

 1,223,773 

 

 

 1,217,399 

 

 

 1,215,287 

 

 

 1,212,306 

 

 

1,207,467 




27


Item 7.

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


NORTHEAST UTILITIES AND SUBSIDIARIES


The following discussion and analysis should be read in conjunction with our consolidated financial statements and related combined notes included in this Annual Report on Form 10-K.  References in this Annual Report on Form 10-K to "NU," the "Company," "we," "us," and "our" refer to Northeast Utilities and subsidiaries.  Our merger was effective April 10, 2012, and all subsequent results of operations and cash flows include NSTAR and its subsidiaries throughout this Management's Discussion and Analysis of Financial Condition and Results of Operations.  On February 2, 2015, NU, CL&P, NSTAR Electric, PSNH and WMECO commenced doing business as Eversource Energy.  


All per share amounts are reported on a diluted basis.  The consolidated financial statements of NU, NSTAR Electric and PSNH and the 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 Annual Report on Form 10-K 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 of such business but rather represent a direct interest in our assets and liabilities as a whole.  EPS by business is a financial measure not recognized under GAAP that is calculated by dividing the Net Income Attributable to Controlling Interest of each business by the weighted average diluted NU common shares outstanding for the year.  The discussion below also includes non-GAAP financial measures referencing our 2014, 2013 and 2012 earnings and EPS excluding certain integration and merger 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 2014, 2013 and 2012 results without including the impact of these 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.  


Financial Condition and Business Analysis


Executive Summary


The following items in this executive summary are explained in more detail in this Management's Discussion and Analysis of Financial Condition and Results of Operations:  


Results:


·

We earned $819.5 million, or $2.58 per share, in 2014, compared with $786 million, or $2.49 per share, in 2013.  Excluding integration costs, we earned $841.6 million, or $2.65 per share, in 2014 and $799.8 million, or $2.53 per share, in 2013.  


·

Our electric distribution segment, which includes generation, earned $462.4 million, or $1.45 per share, in 2014, compared with $427 million, or $1.35 per share, in 2013.  Our transmission segment earned $295.4 million, or $0.93 per share, in 2014, compared with $287 million, or $0.91 per share, in 2013.  Our natural gas distribution segment earned $72.3 million, or $0.23 per share, in 2014, compared with $60.9 million, or $0.19 per share, in 2013.


·

NU parent and other companies had a net loss of $10.6 million, or $0.03 per share, in 2014, compared with earnings of $11.1 million, or $0.04 per share, in 2013.  The 2014 and 2013 results reflect $22.1 million, or $0.07 per share, and $13.8 million, or $0.04 per share, respectively, of integration costs.


Legislative, Regulatory, Policy and Other Items:


·

Pursuant to the FERC orders issued and other developments in the pending base ROE complaint proceedings further described in the "FERC Regulatory Issues – FERC Base ROE Complaints" section of this Management's Discussion and Analysis of Financial Condition and Results of Operations, the Company recorded reserves at its electric subsidiaries to recognize the potential financial impact of these rulings and developments in both 2014 and 2013.  The net aggregate after-tax charge to earnings totaled $22.4 million and $14.3 million in 2014 and 2013, respectively.  


·

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.  On February 18, 2015, NU, Spectra Energy Corp and National Grid announced the addition of National Grid as a co-developer in the project for a total ownership interest of 20 percent, with NU and Spectra Energy Corp each owning 40 percent.  The total project cost, subject to FERC approval, is expected to be approximately $3 billion and has an anticipated in-service date of November 2018.




28


·

In September 2014, pursuant to legislation enacted in 2014, the NHPUC opened a docket that required them to commence and expedite a proceeding to determine whether all or some of PSNH's generation assets should be divested.  An NHPUC progress report must be completed by March 31, 2015.  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.  On December 26, 2014, PSNH requested that the NHPUC stay this proceeding in order to allow discussions to take place with other significant parties to determine whether a collaborative resolution of all issues was achievable.  On January 15, 2015, the NHPUC issued an order granting the motion to stay in this proceeding, and settlement discussions have ensued.


·

On December 17, 2014, PURA issued a final decision in CL&P's rate case, effective December 1, 2014, for a total distribution rate increase of $134 million.  The distribution rate increase included a revenue decoupling reconciliation mechanism, system resiliency costs, and, pursuant to a March 12, 2014 PURA order approving such costs, the recovery of 2011 and 2012 storm restoration costs over a six-year period.  In addition, CL&P began recovering the 2013 storm costs and residual 2012 Storm Sandy costs over a seven-year period beginning December 1, 2014.  Including the $65.4 million of DOE Phase II Damages proceeds CL&P was allowed to credit to its deferred storm costs, CL&P has now been approved to recover all of its previously deferred storm costs in distribution rates.


·

On December 31, 2014, NSTAR Electric, NSTAR Gas and the Massachusetts Attorney General filed a comprehensive settlement agreement with the DPU.  The comprehensive settlement agreement included resolution of the outstanding NSTAR Electric CPSL program filings, the NSTAR Electric and NSTAR Gas PAM and energy efficiency-related customer billing adjustments reported in 2012, and the NSTAR Electric energy efficiency program filings regarding LBR.  If approved by the DPU, NSTAR Electric and NSTAR Gas will be required to refund a total of $44.7 million to their respective customers, which was included in our regulatory liabilities as of December 31, 2014.  Upon the DPU's approval, we will adjust our regulatory liabilities, which we expect will result in an after-tax benefit of approximately $14 million.  We expect a response from the DPU in the first quarter of 2015.  


Liquidity:


·

Cash and cash equivalents totaled $38.7 million as of December 31, 2014, compared with $43.4 million as of December 31, 2013.


·

Investments in property, plant and equipment totaled $1.6 billion in 2014 and $1.5 billion in 2013.


·

Cash flows provided by operating activities totaled $1.64 billion in 2014, compared with $1.66 billion in 2013.  As compared to 2013, the 2014 operating cash flows were favorably impacted by 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 2013 cash disbursements for major storm restoration costs, the decrease of approximately $130 million in Pension and PBOP Plan cash contributions, and changes in the timing of working capital items.  These favorable impacts were more than offset by higher income tax payments in 2014 and the unfavorable cash flow impact resulting from lower recoveries from customers in 2014, as compared to 2013, relating to regulatory cost recovery tracking mechanisms.  


·

In 2014, we issued $725 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, $250 million by CL&P on April 24, 2014 and $75 million by PSNH on October 14, 2014.  In 2014, we repaid $575 million of existing long-term debt consisting of $75 million by Yankee Gas on January 1, 2014, $300 million by NSTAR Electric on April 15, 2014, $50 million by PSNH on July 15, 2014, and $150 million by CL&P on September 15, 2014.  On January 15, 2015, NU parent issued $450 million of new long-term debt.


·

In 2014, we had cash dividends on common shares of $475.2 million, compared with $462.7 million in 2013.  On February 3, 2015, our Board of Trustees approved a common dividend payment of $0.4175 per share, payable on March 31, 2015 to shareholders of record as of March 2, 2015, which represents an increase of 6.4 percent over the dividend paid in December 2014, and is equivalent to a dividend on common shares of approximately $530 million on an annual basis.


·

We project to make capital expenditures of approximately $8.4 billion from 2015 through 2018.  Of the $8.4 billion, we expect to invest approximately $4.2 billion in our electric and natural gas distribution segments and $3.9 billion in our electric transmission segment.  In addition, we project to invest approximately $360 million in information technology and facilities upgrades and enhancements.  These projections do not include capital expenditures related to Access Northeast.




29


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, is as follows:


 

 

For the Years Ended December 31,

 

 

2014

 

2013

 

2012 (1)

(Millions of Dollars, Except Per Share Amounts)

 

Amount

 

Per Share

 

Amount

 

Per Share

 

Amount

 

Per Share

Net Income Attributable to Controlling Interest (GAAP)

 

$

819.5 

 

$

2.58 

 

$

786.0 

 

$

2.49 

 

$

525.9 

 

$

1.89 


Regulated Companies

 

$

830.1 

 

$

2.61 

 

$

774.9 

 

$

2.45 

 

$

626.0 

 

$

2.25 

NU Parent and Other Companies

 

 

11.5 

 

 

0.04 

 

 

24.9 

 

 

0.08 

 

 

7.5 

 

 

0.03 

Non-GAAP Earnings

 

 

841.6 

 

 

2.65 

 

 

799.8 

 

 

2.53 

 

 

633.5 

 

 

2.28 

Integration and Merger-Related Costs (after-tax)

 

 

(22.1)

 

 

(0.07)

 

 

(13.8)

 

 

(0.04)

 

 

(107.6)

 

 

(0.39)

Net Income Attributable to Controlling Interest (GAAP)

 

$

819.5 

 

$

2.58 

 

$

786.0 

 

$

2.49 

 

$

525.9 

 

$

1.89 


(1)

Results include the operations of NSTAR beginning April 10, 2012.  


Excluding the impact of integration costs, our 2014 earnings increased by $41.8 million, as compared to 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 approximately $30 million of non-tracked 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.  Partially offsetting this increase was the absence in 2014 of a favorable impact from the resolution of a state income tax audit in 2013, higher property taxes, higher depreciation expense at our regulated companies, 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 also unfavorably impacted by the 2014 after-tax net reserve of $22.4 million related to the 2014 FERC ROE orders, as compared to the 2013 after-tax reserve of $14.3 million related to the 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.  


The 2014 and 2013 integration costs consisted of costs incurred for employee severance in connection with ongoing integration.  As of December 31, 2014, NU employed approximately 8,250 employees, compared to 8,700 as of December 31, 2013.  In addition, the 2014 integration costs included costs associated with our rebranding efforts, as well as costs related to facility closures across our service territories.


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 is as follows:


 

 

For the Years Ended December 31,

 

 

2014

 

2013

 

2012 (1)

(Millions of Dollars, Except Per Share Amounts)

 

Amount

 

Per Share

 

Amount

 

Per Share

 

Amount

 

Per Share

Net Income – Regulated Companies (GAAP)

 

$

830.1 

 

$

2.61 

 

$

774.9 

 

$

2.45 

 

$

572.8 

 

$

 2.06 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Electric Distribution

 

$

462.4 

 

$

1.45 

 

$

427.0 

 

$

1.35 

 

$

343.4 

 

$

1.24 

Transmission

 

 

295.4 

 

 

0.93 

 

 

287.0 

 

 

0.91 

 

 

249.7 

 

 

0.89 

Natural Gas Distribution

 

 

72.3 

 

 

0.23 

 

 

60.9 

 

 

0.19 

 

 

32.9 

 

 

0.12 

Net Income – Regulated Companies (Non-GAAP)

 

 

830.1 

 

 

2.61 

 

 

774.9 

 

 

2.45 

 

 

626.0 

 

 

2.25 

Merger-Related Costs (after-tax) (2)

 

 

 

 

 

 

 

 

 

 

(53.2)

 

 

(0.19)

Net Income - Regulated Companies (GAAP)

 

$

830.1 

 

$

2.61 

 

$

774.9 

 

$

2.45 

 

$

572.8 

 

$

2.06 


(1)

Results include the operations of NSTAR beginning April 10, 2012.  

(2)

Merger-related costs are attributable to the electric distribution segment ($51.1 million) and the natural gas distribution segment ($2.1 million).  


Our electric distribution segment earnings increased $35.4 million in 2014, as compared to 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, as compared to 2013, were higher property taxes and depreciation expense, lower retail electric sales volumes as a result of cooler summer weather in 2014, and the absence in 2014 of regulatory interest income on stranded cost deferrals in 2013.


Our transmission segment earnings increased $8.4 million in 2014, as compared to 2013, due primarily to a decrease in transmission segment state income tax expense and a higher transmission rate base as a result of an increased investment in our transmission infrastructure.  These favorable impacts were partially offset by the after-tax net reserve of $22.4 million related to the 2014 FERC ROE orders, as compared to the $14.3 million after-tax reserve related to the 2013 FERC ALJ initial decision in the FERC base ROE complaints.


Our natural gas distribution segment earnings increased $11.4 million in 2014, as compared to 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.




30



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 Year Ended December 31, 2014 Compared to 2013

 

NU

 

CL&P

 

NSTAR Electric

 

PSNH

 

WMECO

 

 

 

Percentage

 

Percentage

 

 

 

Percentage

 

 

 

Sales Volumes (GWh)

 

Increase/

 

Increase/

 

Percentage

 

Increase/

 

Percentage

Electric

2014

 

2013

 

(Decrease)

 

(Decrease)

 

Decrease

 

Decrease

 

Decrease

Residential

21,317 

 

21,896 

 

(2.6)%

 

(2.8)%

 

(3.0)%

 

(1.1)%

 

(3.2)%

Commercial

27,449 

 

27,787 

 

(1.2)%

 

(1.3)%

 

(1.2)%

 

(0.8)%

 

(2.0)%

Industrial

5,676 

 

5,648 

 

0.5 %

 

2.5 %

 

(1.6)%

 

0.6 %

 

(2.5)%

Total

54,442 

 

55,331 

 

(1.6)%

 

(1.6)%

 

(1.8)%

 

(0.7)%

 

(2.6)%


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


 

For the Year Ended December 31, 2014 Compared to 2013

 

NU

 

Sales Volumes (million cubic feet)

 

Percentage

Firm Natural Gas

2014

 

2013

 

Increase

Residential

38,969 

 

36,777 

 

6.0%

Commercial

42,977 

 

40,215 

 

6.9%

Industrial

22,245 

 

21,266 

 

4.6%

Total

104,191 

 

98,258 

 

6.0%

Total, Net of Special Contracts (1)

99,500 

 

94,083 

 

5.8%


(1)

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


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


Our 2014 consolidated retail electric sales volumes were lower, as compared to 2013, due primarily to cooler summer weather in 2014.  In 2014, cooling degree days were 13 percent lower in Connecticut and western Massachusetts, 17 percent lower in the Boston metropolitan area, and 23 percent lower in New Hampshire, as compared to 2013.  Weather-normalized NU consolidated retail electric sales volumes decreased one percent in 2014, as compared to 2013.  We believe the decrease was due primarily to an increase in customer conservation efforts primarily by our residential customers, including the impact of energy efficiency programs sponsored by CL&P, NSTAR Electric and WMECO.


For WMECO and CL&P (effective December 1, 2014), fluctuations in retail electric sales volumes do not impact earnings due to the regulatory commission approved revenue decoupling mechanisms.  Distribution revenues are decoupled from their customer sales volumes.  CL&P and WMECO reconcile their annual base distribution rate recovery to pre-established levels of baseline distribution delivery service revenues.  Any difference between the allowed level of distribution revenue and the actual amount incurred during a 12-month period is adjusted through rates in the following period.  The decoupling mechanism effectively breaks the relationship between sales volumes and revenues recognized.  Prior to December 1, 2014, CL&P recognized LBR related to reductions in sales volume as a result of successful energy efficiency programs.  LBR was recovered from retail customers through the FMCC.  Effective December 1, 2014, CL&P no longer recognizes LBR due to its revenue decoupling mechanism.  NSTAR Electric continues to recognize LBR through December 31, 2015 in accordance with the 2012 DPU-approved comprehensive merger settlement agreement with the Massachusetts Attorney General.  For the year ended December 31, 2014, CL&P and NSTAR Electric recognized LBR of $5.3 million and $39.9 million, respectively.


Our firm natural gas sales are subject to many of the same influences as our retail electric sales.  In addition, they have benefited from historically favorable natural gas prices and customer growth across both operating companies.  Our 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 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 2014, as compared to 2013.  Weather-normalized NU consolidated firm natural gas sales volumes increased 2.9 percent in 2014, as compared to 2013.


NU Parent and Other Companies:  NU parent and other companies, which include our unregulated businesses, had a net loss of $10.6 million in 2014, compared with earnings of $11.1 million in 2013.  Excluding the impact of integration costs, NU parent and other companies earned $11.5 million in 2014, compared with $24.9 million in 2013.  The earnings decrease in 2014 was due primarily to a higher effective tax rate and the absence in 2014 of the favorable impact from the resolution of the Connecticut state income tax audit.




31


Future Outlook


2015 EPS Guidance:  We currently project 2015 earnings of between $2.75 per share and $2.90 per share, which excludes integration costs.


Liquidity


Consolidated:  Cash and cash equivalents totaled $38.7 million as of December 31, 2014, compared with $43.4 million as of December 31, 2013.


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 repay $25 million in short-term borrowings.


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 using short-term borrowings.


On October 14, 2014, PSNH issued $75 million of first mortgage bonds at a yield of 3.144 percent, due to mature in 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.  The proceeds, net of issuance costs, were used to repay short-term borrowings.  


On January 15, 2015, NU parent issued $150 million of 1.60 percent Series G Senior Notes, due to mature in 2018 and $300 million of 3.15 percent Series H Senior Notes, due to mature in 2025.  The proceeds, net of issuance costs, were used to repay short-term borrowings outstanding under the NU commercial paper program.  


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.


NU parent, CL&P, PSNH, WMECO, NSTAR Gas and Yankee Gas are parties to a five-year $1.45 billion revolving credit facility.  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.  Effective July 23, 2014, NU parent, CL&P, PSNH, WMECO, NSTAR Gas and Yankee Gas extended the expiration date of their joint revolving credit facility for one additional year to September 6, 2019.  CL&P has a borrowing sublimit of $600 million, and PSNH and WMECO each have borrowing sublimits of $300 million.  As of December 31, 2014 and 2013, NU parent had approximately $1.1 billion and $1.01 billion, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $348.9 million and $435.5 million of available borrowing capacity as of December 31, 2014 and 2013, respectively.  The weighted-average interest rate on these borrowings as of December 31, 2014 and 2013 was 0.43 percent and 0.24 percent, respectively, which is generally based on A2/P2 rated commercial paper.  As of December 31, 2014, there were intercompany loans from NU parent of $133.4 million to CL&P, $90.5 million to PSNH and $21.4 million to WMECO.  As of December 31, 2013, there were intercompany loans from NU parent of $287.3 million to CL&P and $86.5 million to PSNH.  


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


Each of NU, CL&P, NSTAR Electric, PSNH and WMECO use its available capital resources to fund its respective construction expenditures, meet debt requirements, pay operating costs, including storm-related costs, pay dividends and fund other corporate obligations, such as pension contributions.  The current growth in NU's construction expenditures utilizes a significant amount of cash for projects that have a long-term return on investment and recovery period.  In addition, NU's Regulated companies recover their electric and natural gas distribution construction expenditures as the related project costs are depreciated over the life of the assets.  This impacts the timing of the revenue stream designed to fully recover the total investment plus a return on the equity portion of the cost and related financing costs.  These factors have resulted in current liabilities exceeding current assets by approximately $442 million, $177 million, $133 million and $24 million at NU, CL&P, NSTAR Electric and WMECO, respectively, as of December 31, 2014.


As of December 31, 2014, $216.7 million of NU's obligations classified as current liabilities relates to long-term debt that will be paid in the next 12 months, consisting of $162 million for CL&P, $4.7 million for NSTAR Electric and $50 million for WMECO.  The remaining $28.9 million of NU's obligations classified as current liabilities relates to fair value adjustments from the merger that will be amortized in the next 12 months and have no cash flow impact.  NU, with its strong credit ratings, has several options available in the financial markets to repay or refinance these maturities with the issuance of new long-term debt.  NU, CL&P, NSTAR Electric, PSNH and WMECO will reduce their short-term borrowings with cash received from operating cash flows or with the issuance of new long-term debt, determined considering capital requirements and maintenance of NU's credit



32


rating and profile.  Management expects the future operating cash flows of NU, CL&P, NSTAR Electric, PSNH and WMECO, along with the access to financial markets, will be sufficient to meet any future operating requirements and capital investment forecasted opportunities.


Cash flows provided by operating activities totaled $1.64 billion in 2014, compared with $1.66 billion in 2013 and $1.16 billion in 2012.  The 2014 operating cash flows were favorably impacted by 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 2013 cash disbursements for major storm restoration costs, the decrease of approximately $130 million in Pension and PBOP Plan cash contributions and changes in the timing of working capital items.  These favorable impacts were more than offset by higher income tax payments in 2014 and the unfavorable cash flow impact resulting from lower recoveries from customers in 2014, as compared to 2013, relating to regulatory cost recovery tracking mechanisms.  For further information on the spent nuclear fuel litigation, see Note 11C, "Commitments and Contingencies – Contractual Obligations – Yankee Companies," in this combined Annual Report on Form 10-K.  The improved operating cash flows in 2013, as compared to 2012, were due primarily to the addition of NSTAR, a decrease in cash disbursements for storm restoration, and the absence in 2013 of cash disbursements related to customer bill credits and merger-related payments made in 2012.  Partially offsetting these favorable cash flow impacts was an increase in Pension Plan cash contributions, increases in fuel inventories, and changes in traditional working capital amounts due primarily to the timing of accounts receivable and accounts payable.


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


 

 

Moody's

 

S&P

 

Fitch

 

 

Current

 

Outlook

 

Current

 

Outlook

 

Current

 

Outlook

NU Parent

 

Baa1

 

Stable

 

A-

 

Positive

 

BBB+

 

Stable

CL&P

 

Baa1

 

Stable

 

A-

 

Positive

 

BBB+

 

Stable

NSTAR Electric

 

A2

 

Stable

 

A-

 

Positive

 

A

 

Stable

PSNH

 

Baa1

 

Stable

 

A-

 

Positive

 

BBB+

 

Stable

WMECO

 

A3

 

Stable

 

A-

 

Positive

 

BBB+

 

Stable


A summary of the current credit ratings and outlooks by Moody's, S&P and Fitch for senior unsecured debt of NU parent, NSTAR Electric, and WMECO and senior secured debt of CL&P and PSNH is as follows:


 

 

Moody's

 

S&P

 

Fitch

 

 

Current

 

Outlook

 

Current

 

Outlook

 

Current

 

Outlook

NU Parent

 

Baa1

 

Stable

 

BBB+ 

 

Positive

 

BBB+ 

 

Stable

CL&P

 

A2

 

Stable

 

 

Positive

 

 

Stable

NSTAR Electric

 

A2

 

Stable

 

A-

 

Positive

 

A+

 

Stable

PSNH

 

A2

 

Stable

 

 

Positive

 

A  

 

Stable

WMECO

 

A3

 

Stable

 

A-

 

Positive

 

A-

 

Stable


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


In 2014, we had cash dividends on common shares of $475.2 million, compared with $462.7 million in 2013.  On December 31, 2014, we paid a common dividend of $0.3925 per share, which was approved by our Board of Trustees on December 3, 2014, to shareholders of record as of December 15, 2014.  On February 3, 2015, our Board of Trustees approved a common dividend payment of $0.4175 per share, payable on March 31, 2015 to shareholders of record as of March 2, 2015.  The dividend represented an increase of 6.4 percent over the dividend paid in December 2014.


In 2014, CL&P, NSTAR Electric, PSNH, and WMECO paid $171.2 million, $253 million, $66 million, and $60 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 2014, investments for NU, CL&P, NSTAR Electric, PSNH, and WMECO were $1.6 billion, $515.7 million, $465 million, $256.2 million, and $116.2 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 $1.7 billion in 2014, $1.6 billion in 2013, and $1.5 billion in 2012.  These amounts included $58.3 million in 2014, $44.7 million in 2013, and $43.1 million in 2012, related to information technology and facilities upgrades and enhancements, primarily at NUSCO and The Rocky River Realty Company.


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.  On February 18, 2015, NU, Spectra Energy Corp and National Grid announced the addition of National Grid as a co-developer in the project for a total ownership interest of 20 percent, with NU and Spectra Energy Corp each owning 40 percent.  The total project cost, subject to FERC approval, is expected to be approximately $3 billion and has an anticipated in-service date of November 2018.



33



On December 8, 2014, NU and Spectra Energy Corp announced an alliance with Iroquois Gas Transmission for the Access Northeast project.  This alliance will provide New England natural gas distribution companies and generators with additional access to natural gas supplies from multiple, diverse receipt points along the Algonquin pipeline system, including the Iroquois pipeline system.


Transmission Business:  Overall, transmission business capital expenditures increased by $41.1 million in 2014, as compared to 2013.  A summary of transmission capital expenditures by company is as follows:  


 

 

For the Years Ended December 31,

(Millions of Dollars)

 

2014

 

2013

 

2012 (1)

CL&P

 

$

259.2 

 

$

 211.9 

 

$

 182.5 

NSTAR Electric

 

 

223.8 

 

 

 220.8 

 

 

 160.7 

PSNH

 

 

120.8 

 

 

 99.7 

 

 

 55.7 

WMECO

 

 

68.5 

 

 

 87.2 

 

 

 214.7 

NPT

 

 

28.3 

 

 

 39.9 

 

 

 35.4 

Total Transmission Segment

 

$

700.6 

 

$

 659.5 

 

$

 649.0 


(1)

Results include the transmission capital expenditures of NSTAR Electric beginning April 10, 2012.  


NEEWS:  GSRP, the first, largest and most complicated project within the NEEWS family of projects, was fully energized on November 20, 2013.  As of December 31, 2014, CL&P and WMECO have placed $642 million in service.


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.  All siting approvals have been received and construction is underway in all three states.  NU's portion of the cost is estimated to be $218 million, and IRP was approximately 78 percent complete as of December 31, 2014.  As of December 31, 2014, CL&P had placed $35 million in service.  We expect to complete IRP by the end of 2015.


The Greater Hartford Central Connecticut Study (GHCC) includes the reassessment of the Central Connecticut Reliability Project and continues to make progress.  The final need results showed existing and worsening severe regional and local thermal overloads and voltage violations within each of the areas studied and across the interfaces of those areas.  These results were presented to the ISO-NE Planning Advisory Committee in November 2013.  On July 15, 2014, ISO-NE presented the preferred transmission solutions to its Planning Advisory Committee.  These solutions are comprised of many 115 kV upgrades and 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, $96 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 December 31, 2014, CL&P and WMECO capitalized $351.5 million and $573.6 million, respectively, in costs associated with NEEWS, of which $98.7 million and $6.6 million, respectively, were capitalized in 2014.  Included in the NEEWS amounts are costs for IRP, of which CL&P capitalized $168.8 million in costs through December 31, 2014, and $95.8 million related to costs capitalized in 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.  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 currently expect the DOE to issue the draft EIS in April 2015.  We expect to file the state permit application in mid-2015 after receipt of the draft EIS.  The $1.4 billion project is subject to comprehensive federal and state public permitting processes and is expected to be operational in the second half of 2018.  


Greater Boston Reliability Solutions:  NSTAR Electric and PSNH expect to implement a series of new transmission projects over the next five years to enhance the region's system reliability.  On February 12, 2015, ISO-NE selected NU's and National Grid's proposed Greater Boston and New Hampshire Solution (Solution) as its preferred option because it is significantly less expensive than an alternate proposal and has superior performance criteria.  The Solution consists of a portfolio of important electric transmission upgrades encompassing the Merrimack Valley and metropolitan Boston areas of southern New Hampshire and eastern Massachusetts.  Our estimated investment in the Solution chosen by ISO-NE is $489 million and we will now pursue the necessary regulatory approvals.




34


Distribution Business:  A summary of distribution capital expenditures by company is as follows:


 

For the Years Ended December 31,

(Millions of Dollars)

2014

 

2013

 

2012 (1)

CL&P:

 

 

 

 

 

 

 

 

  Basic Business

$

120.2 

 

$

60.9 

 

$

69.2 

  Aging Infrastructure

 

118.0 

 

 

160.7 

 

 

177.8 

  Load Growth

 

66.3 

 

 

76.9 

 

 

65.8 

Total CL&P

 

304.5 

 

 

298.5 

 

 

312.8 

NSTAR Electric:

 

 

 

 

 

 

 

 

  Basic Business  

 

99.0 

 

 

98.5 

 

 

47.3 

  Aging Infrastructure

 

104.2 

 

 

110.6 

 

 

111.5 

  Load Growth

 

43.1 

 

 

53.6 

 

 

17.4 

Total NSTAR Electric

 

246.3 

 

 

262.7 

 

 

176.2 

PSNH:

 

 

 

 

 

 

 

 

  Basic Business

 

62.1 

 

 

22.7 

 

 

25.3 

  Aging Infrastructure

 

45.3 

 

 

50.5 

 

 

50.2 

  Load Growth

 

27.1 

 

 

29.3 

 

 

20.2 

Total PSNH

 

134.5 

 

 

102.5 

 

 

95.7 

WMECO:

 

 

 

 

 

 

 

 

  Basic Business

 

19.0 

 

 

7.9 

 

 

12.7 

  Aging Infrastructure

 

16.1 

 

 

24.6 

 

 

18.5 

  Load Growth

 

6.1 

 

 

9.2 

 

 

6.5 

Total WMECO

 

41.2 

 

 

41.7 

 

 

37.7 

Total - Electric Distribution (excluding Generation)

 

726.5 

 

 

705.4 

 

 

622.4 

Other Distribution

 

 

 

0.7 

 

 

0.1 

PSNH Generation

 

13.1 

 

 

9.7 

 

 

29.9 

WMECO Generation

 

7.6 

 

 

4.5 

 

 

0.7 

Total - Natural Gas

 

193.7 

 

 

175.2 

 

 

162.9 

Total Distribution Segment

$

940.9 

 

$

895.5 

 

$

816.0 


(1)

Results include the electric and natural gas distribution capital expenditures of NSTAR beginning April 10, 2012.  


For the electric distribution business, basic business includes the purchase of meters, tools, vehicles, information technology, transformer replacements, equipment facilities, and the relocation of plant.  Aging infrastructure relates to reliability and the replacement of overhead lines, plant 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.  


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


On October 31, 2014, pursuant to new legislation, NSTAR Gas filed the Gas System Enhancement Program (GSEP) with the DPU.  NSTAR Gas' program accelerates the replacement of certain natural gas distribution facilities in the system within 25 years.  The GSEP includes a new tariff that provides NSTAR Gas an opportunity to collect the costs for the program on an annual basis through a newly designed reconciling factor to be approved by the DPU.  We expect a decision on the program in April 2015.  We have projected capital expenditures of approximately $200 million for the period 2015 through 2018 for the GSEP, which are consistent with our request in the NSTAR Gas rate case application currently before the DPU.




35


Projected Capital Expenditures:  A summary of the projected capital expenditures for the Regulated companies' electric transmission and for the total electric distribution, generation, and natural gas distribution businesses for 2015 through 2018, including information technology and facilities upgrades and enhancements on behalf of the Regulated companies, is as follows:


 

Years

(Millions of Dollars)

2015

 

2016

 

2017

 

2018

 

2015-2018
Total

CL&P Transmission

$

214 

 

$

241 

 

$

258 

 

$

158 

 

$

871 

NSTAR Electric Transmission

 

231 

 

 

262 

 

 

236 

 

 

295 

 

 

1,024 

PSNH Transmission

 

133 

 

 

76 

 

 

73 

 

 

19 

 

 

301 

WMECO Transmission

 

128 

 

 

80 

 

 

34 

 

 

 

 

250 

NPT

 

34 

 

 

309 

 

 

620 

 

 

466 

 

 

1,429 

  Total Transmission

$

740 

 

$

968 

 

$

1,221 

 

$

946 

 

$

3,875 

Electric Distribution

$

755 

 

$

778 

 

$

758 

 

$

748 

 

$

3,039 

Generation

 

38 

 

 

20 

 

 

15 

 

 

15 

 

 

88 

Natural Gas

 

228 

 

 

256 

 

 

275 

 

 

300 

 

 

1,059 

  Total Distribution

$

1,021 

 

$

1,054 

 

$

1,048 

 

$

1,063 

 

$

4,186

Information Technology and All Other

$

90 

 

$

92 

 

$

94 

 

$

83 

 

$

359 

Total

$

1,851 

 

$

2,114 

 

$

2,363 

 

$

2,092 

 

$

8,420 


The projections do not include capital expenditures related to Access Northeast.  Actual capital expenditures could vary from the projected amounts for the companies and years above.


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, 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 2013, the Company recorded reserves at its electric subsidiaries to recognize the potential financial impact from the FERC ALJ's initial decision for the first complaint refund period.     


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 consistent with the method 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 2014, and briefs were filed in August and September 2014 by the parties on the appropriate long-term growth rate.  


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 prospective new base ROE at this time.  In November 2014, the NETOs requested rehearing and clarification from FERC.  In late 2014, the NETOs made a compliance filing, and began refunding amounts from the first complaint period, inclusive of incentive ROE adders that exceeded the 11.74 percent as compared to the total company transmission ROE.  Complainants have challenged the compliance filing.


In 2014, the Company recorded additional reserves at its electric subsidiaries to recognize the potential financial impact from the FERC's orders.    


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"), challenging the NETOs' existing base ROE, requesting FERC to reduce the NETOs' base ROE prospectively from the date of the final FERC order and seeking refunds for the 15-month period of December 27, 2012 to March 27, 2014 (the "second complaint refund period").


On June 19, 2014, FERC issued an order finding that the second complaint raised issues of material fact, and setting the complaint for settlement or hearing.  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 set a trial date beginning June 8, 2015, and indicated he could issue an initial decision on or before October 26, 2015.  This schedule was subsequently modified by a November 24, 2014 order on the third complaint (see below).  In 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.    



36



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 NETOs' base ROE prospectively from the date of a final FERC order, and seeking refunds for the 15-month period of July 31, 2014 to October 31, 2015 (the "third complaint refund period").  On November 24, 2014, FERC issued an order finding that the third complaint raised issues of material fact and set the case for trial.  In this order, FERC also consolidated the third complaint with the second complaint for purposes of hearing and decision.  Due to the establishment of two refund periods, the FERC also stated that it is appropriate for the parties to litigate a separate ROE for each refund period.  On December 24, 2014, the NETOs filed for rehearing of this order.  The trial judge has set a hearing beginning June 23, 2015 for the two complaints.  The trial judge's recommended initial decision is expected by November 30, 2015 with a FERC order issued by September 30, 2016.  


Rehearing requests of NETOs that were filed in all three complaint proceedings have not yet been acted upon by FERC.  At this time, the Company cannot determine the outcome of these rehearing requests.


Cumulative Reserves:  The following is a summary of the cumulative pre-tax reserves (excluding interest) that the Company established in 2013 and 2014 to recognize the potential financial impacts of the first and second complaints.  The Company is unable to determine any amount related to the third complaint.    


 

 

NU

 

 

 

 

 

 

 

 

 

 

 

For the Years Ended December 31,

 

 

 

 

 

 

 

 

 

(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)

 

 - 

 

 

 8.4 

 

 

 8.4 

 

 

 

 

 

 

 

 

 

Cumulative Reserve

$

 23.7 

 

$

 37.0 

 

$

 60.7 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CL&P

 

NSTAR Electric

 

 

For the Years Ended December 31,

 

For the Years Ended December 31,

(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)

 

 - 

 

 

 6.7 

 

 

 6.7 

 

 

 - 

 

 

 - 

 

 

 - 

Cumulative Reserve

$

 12.8 

 

$

 20.7 

 

$

 33.5 

 

$

 5.7 

 

$

 7.9 

 

$

 13.6 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

PSNH

 

WMECO

 

 

For the Years Ended December 31,

 

For the Years Ended December 31,

(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)

 

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 1.7 

 

 

 1.7 

Cumulative Reserve

$

 2.3 

 

$

 2.8 

 

$

 5.1 

 

$

 2.9 

 

$

 5.6 

 

$

 8.5 


As of December 31, 2014, the cumulative reserves above do not reflect refunds totaling $4.8 million at NU, $2.7 million at CL&P, $1 million at NSTAR Electric, $0.5 million at PSNH and $0.6 million at WMECO for the first complaint refund period.  


In the fourth quarter of 2014, we finalized our reserve analysis based on the October FERC order and our subsequent refund filing.  As a result, the net aggregate after-tax charge to 2014 earnings resulting from the June 19, 2014 and October 16, 2014 FERC orders totaled $22.4 million at NU, $12.4 million at CL&P, $4.9 million at NSTAR Electric, $1.7 million at PSNH and $3.4 million at WMECO.  In 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.


Regulatory Developments and Rate Matters


Electric and Natural Gas Base Distribution Rates:  


Each NU utility subsidiary is subject to the regulatory jurisdiction of the state in which it operates:  CL&P and Yankee Gas operate in Connecticut and are subject to PURA regulation; NSTAR Electric, WMECO and NSTAR Gas operate in Massachusetts and are subject to DPU regulation; and PSNH operates in New Hampshire and is subject to NHPUC regulation.  


In Connecticut, CL&P distribution rates were established in a 2014 PURA approved rate case.  See Connecticut – Distribution Rates in this Regulatory Developments and Rate Matters section for further information.  Yankee Gas distribution rates were established in a 2011 PURA approved rate case.  


In Massachusetts, electric utility companies are required to file at least one distribution rate case every five years and natural gas companies to file at least one distribution rate case every 10 years, and those companies are limited to one settlement agreement in any 10-year period.  Pursuant to the April 2012 DPU-approved Massachusetts comprehensive merger settlement agreements, NSTAR Electric, WMECO and NSTAR Gas are subject to a base distribution rate freeze through December 31, 2015.  On December 17, 2014, NSTAR Gas filed an application with the DPU to amend base distribution rates, effective January 1, 2016.  


In New Hampshire, PSNH is currently operating under the 2010 NHPUC approved distribution rate case settlement, which is effective through June 30, 2015.  Under the settlement, PSNH is permitted to file a request to collect certain exogenous costs and step increases on an annual basis.  See New Hampshire - Distribution Rates in this Regulatory Developments and Rate Matters section for further information.



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Major Storms:


CL&P, NSTAR Electric, PSNH and WMECO experienced several significant storm events, including Tropical Storm Irene in 2011, the October 2011 snowstorm, Storm Sandy in 2012, and the February 2013 blizzard.  As a result of these storm events, each company suffered extensive damage to its distribution and transmission systems resulting in customer outages.  Each company incurred significant costs to repair damage and restore customers' service.  In addition, on November 26, 2014, a snowstorm caused damage to the electric delivery systems of PSNH and WMECO.  This snowstorm resulted in estimated deferred storm restoration costs of approximately $23 million at PSNH and approximately $3 million at WMECO.  


The magnitude of these storm restoration costs met the criteria for cost deferral in Connecticut, Massachusetts, and New Hampshire.  As a result, the storms had no material impact on the results of operations of CL&P, NSTAR Electric, PSNH and WMECO.  We believe the storm restoration costs were prudent and meet the criteria for specific cost recovery in Connecticut, Massachusetts and New Hampshire, and that recovery from customers is probable through the applicable regulatory recovery process.  Each electric utility has sought, or is seeking, recovery of its deferred storm restoration costs through its applicable regulatory recovery process.  As of December 31, 2014, all CL&P deferred storm costs have been reviewed and approved for recovery in distribution rates, NSTAR Electric received DPU approval for recovery of $34.2 million of deferred storm costs related to Tropical Storm Irene in 2011 and the October 2011 snowstorm, PSNH received an NHPUC audit report, which found no exception with storm costs from 2011 through March 2013, and WMECO received DPU approval to begin recovering the October 2011 snowstorm and 2012 Storm Sandy restoration costs, of which the DPU approved the majority of deferred storm costs through 2011.


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, as it did not believe that substantial evidence existed to support such penalties, while it upheld the WMECO penalties.  Subsequently, the DPU reinstated approximately $0.4 million of NSTAR Electric storm penalties pursuant to a December 22, 2014 order.


Connecticut:


Distribution Rates:  On June 9, 2014, CL&P filed an application with PURA to amend distribution rates, effective December 1, 2014.  The application included an increase to base distribution rates, as well as increases for the recovery of previously approved 2011 and 2012 deferred storm restoration costs and previously approved electric system resiliency costs.  After the legal briefing process, CL&P updated its requested increase to reflect a reduction to the storm cost recovery amounts.  The reduction primarily related 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.  


On December 17, 2014, PURA issued a final order and approved a total distribution rate increase of $134 million, which includes an authorized ROE of 9.02 percent for the first twelve month period and 9.17 percent thereafter.  The 2011 and 2012 storm costs were approved in their entirety, to be recovered over a six-year period, and adjustments to storm cost recovery and system resiliency cost recovery reflect the lower approved ROE.  PURA granted a re-opener to the rate application for further review of the appropriate treatment of deferred income taxes for rate base purposes.  If PURA concludes that CL&P's treatment of its deferred taxes for rate base purposes is correct, it would result in an additional annual increase to total distribution rates of $22 million.  CL&P is currently responding to information requests and has provided additional information with respect to the treatment of deferred income taxes for rate base purposes and expects a decision no later than the third quarter of 2015.  


The PURA also approved the establishment of a revenue decoupling reconciliation mechanism, effective December 1, 2014, whereby actual base distribution rate recovery is reconciled with pre-established revenue requirement level on an annual basis.  Any difference between the allowed level of distribution revenue and the actual amount incurred in a calendar year is adjusted through rates in the following year.  The baseline allowed distribution revenue is $1.041 billion, which will remain constant until CL&P's next rate case.  With the implementation of the decoupling mechanism, LBR will no longer be recognized effective December 1, 2014, and CL&P will not experience significant fluctuations to its base distribution revenues regardless of the impact of weather and energy efficiency by its customers.  


The PURA also allowed CL&P recovery of $31.1 million in 2013 storm costs and residual 2012 Storm Sandy costs over a seven-year period beginning December 1, 2014.  


CL&P 2014 Storm Order:  On March 12, 2014, 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 and ordered CL&P to capitalize approximately $18 million of the deferred storm restoration costs as utility plant, which will be recovered through depreciation expense in future rate proceedings.  On December 1, 2014, CL&P began recovering approximately $300 million in its distribution rates over a six-year period, which was net of $65.4 million of DOE Phase II Damages proceeds.  The remaining costs were either disallowed or are probable of recovery from other sources.  These costs did not have a material impact on CL&P's financial position or results of operations.


CL&P Standard Service and Last Resort Service Rates:  CL&P's residential and small to intermediate commercial and industrial customers who do not choose competitive energy suppliers are served under SS rates, and large commercial and industrial customers who do not choose competitive energy suppliers are served under LRS rates.  Effective January 1, 2015, the PURA approved an increase to CL&P's energy supply portion of the total average SS rate to 12.446 cents per kWh and the energy supply portion of the total average LRS rate to 17.714 cents per kWh.  These changes were due primarily to the market conditions for the procurement of energy.  The SS and LRS rates reflect CL&P's costs to procure energy for its customers.  Adjustments to these rates do not impact earnings, as CL&P is fully recovering the costs of its SS and LRS services from customers.




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CL&P CTA and SBC Reconciliation:  CL&P filed its 2013 CTA and SBC reconciliation on March 31, 2014, which compared CTA and SBC billed revenues to revenue requirements, as required by PURA.  The 2013 reconciliation filing produced net over recoveries of $16.9 million and $4.3 million for the CTA and SBC, respectively, and was approved by PURA.


CL&P FMCC Filing:  CL&P files with PURA its FMCC filing, which reconciles actual FMCC revenues and charges and GSC revenues and expenses.  The filing identifies a total net over or under recovery, which includes the remaining uncollected or non-refunded portions from previous filings.  On February 3, 2014, CL&P filed with PURA its FMCC filing for the period July 1, 2013 through December 31, 2013.  The filing identified a total net over recovery through December 31, 2013 of $24.1 million and was approved by PURA.  


CL&P Conservation Adjustment Mechanism:  In 2012, CL&P filed an application with PURA for the establishment of a CAM.  The CAM would collect the costs associated with expanded energy efficiency programs beyond that already collected through the statutory charge and the revenues lost because of the expanded energy efficiency programs.  In 2013, DEEP approved CL&P's request of an expanded conservation spending budget and reiterated that PURA is directed to approve a CAM to fund the expanded conservation budget.  The PURA approved a CAM effective January 1, 2014 subject to a future review of its revenue and expense reconciliation filing to be submitted by CL&P.  CL&P has continued its approved January 1, 2014 CAM rate through 2015.


Massachusetts:


Basic Service Rates:  Electric distribution companies in Massachusetts are required to obtain and resell power to retail customers through Basic Service for those customers who choose not to buy energy from a competitive energy supplier.  Basic Service rates are reset every six months (every three months for large commercial and industrial customers).  NSTAR Electric and WMECO fully recover their energy costs through DPU-approved regulatory rate mechanisms.


2015 Annual Reconciliation Filing:  In the fourth quarter of 2014, NSTAR Electric and WMECO filed separately their respective 2015 annual cost recovery mechanisms, including the mechanisms to collect the costs to provide retail transmission, energy supply and energy efficiency services to its customers as well as the costs related to pension and other post-retirement employee benefit costs.  The reconciliation filings compared the total revenues to revenue requirements related to these services.  In December 2014, the DPU issued a final decision approving the rates as filed, subject to future review and reconciliation.


Energy Efficiency Plans:  In accordance with Massachusetts law passed in 2008 known as the Green Communities Act, natural gas and electric distribution companies must file three-year energy efficiency plans, which were initially filed by NSTAR Electric and WMECO, and approved by the DPU, in 2010 covering the period 2010 through 2012.  The NSTAR Electric and WMECO three-year plans covering the period 2013 through 2015 were approved by the DPU in 2013.  Distribution companies that do not yet have rate decoupling mechanisms in place, like NSTAR Electric, include LBR rate adjustment mechanisms in order to offset reduced distribution rate revenues as a result of successful energy efficiency programs.  NSTAR Electric's LBR rate adjustment mechanism is in place through December 31, 2015.


DPU Safety and Reliability Programs (CPSL):  The CPSL program allows NSTAR Electric to recover $15 million per year related to DPU approved safety and reliability programs, which are designed to mitigate stray voltage and repair and replace portions of the system to increase and enhance customer safety.  This annual level of recovery was established by the 2012 DPU-approved comprehensive merger settlement agreement with the Massachusetts Attorney General.  The CPSL program will expire on December 31, 2015.


2014 Comprehensive Settlement Agreement:  On December 31, 2014, NSTAR Electric, NSTAR Gas and the Massachusetts Attorney General filed a comprehensive settlement agreement with the DPU.  The comprehensive settlement agreement included resolution of the outstanding NSTAR Electric CPSL program filings for the periods 2006 through 2011, the NSTAR Electric and NSTAR Gas PAM and energy efficiency-related customer billing adjustments reported in 2012, and the NSTAR Electric energy efficiency program filings regarding LBR for the periods 2008 through 2011.  If approved by the DPU, NSTAR Electric and NSTAR Gas will be required to refund a total of $44.7 million to their respective customers, which was included in our regulatory liabilities as of December 31, 2014.  Upon the DPU's approval, we will adjust our regulatory liabilities, which we expect will result in an after-tax benefit of approximately $14 million.  We expect a response from the DPU in the first quarter of 2015.  


Basic Service Bad Debt Adder:  In accordance with a generic 2005 DPU order, electric utilities in Massachusetts recover the energy-related portion of bad debt costs in their Basic Service rates.  In 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.  NSTAR Electric's position was that it had fully removed the collection of energy-related bad debt costs from its distribution rates effective January 1, 2006.  Therefore, no further adjustment to distribution rates was warranted.  In 2012, the SJC vacated the DPU order and remanded the matter to the DPU for further review.  


As of December 31, 2014, NSTAR Electric has a total deferred regulatory asset of approximately $33 million of costs associated with energy-related bad debt.


On January 7, 2015, the DPU issued an order on remand stating that NSTAR Electric had, in fact, removed energy-related bad debt costs from distribution rates effective January 1, 2006.  The DPU order approved NSTAR Electric's 2005 and 2006 reconciliation filings and ordered NSTAR Electric and the Massachusetts Attorney General to collaborate on the submission of a proposal for the reconciliation of energy-related bad debt costs for the open years of 2007 through 2014 by April 7, 2015.  Management expects to present a proposal to the Attorney General in the first quarter of 2015 with a decision from the DPU later in 2015.



39



Long-Term Wind Contracts:  On January 6, 2015, NSTAR Electric terminated a 15-year renewable energy contract with Cape Wind Associates, LLC due to Cape Wind Associates, LLC's failure to fulfill obligations under the contract.  Under this contract, NSTAR Electric would have purchased 129 MW of renewable energy from an offshore wind energy facility, which was scheduled to achieve commercial operation by December 2016.  As a result, and in accordance with the 2012 DPU-approved comprehensive merger settlement agreement with the DOER, NSTAR Electric will issue a request for proposal (RFP) for new Massachusetts RPS Class I qualified renewable contracts with a term of at least 15 years, for approximately 2 percent of its electric load requirement.  The RFP shall be issued no later than March 31, 2016 in accordance with the provisions of the procurement obligations of the Green Communities Act.  


NSTAR Gas Distribution Rates:  On December 17, 2014, NSTAR Gas filed an application with the DPU requesting an increase in rates, effective January 1, 2016.  NSTAR Gas requested an increase in base distribution rates of $33.9 million.  We expect a final decision in the fourth quarter of 2015.  


New Hampshire:


Distribution Rates:  In 2014, PSNH filed for a distribution rate decrease in accordance with the Earnings Sharing Agreement addressed in the 2010 NHPUC approved distribution rate case settlement.  On June 27, 2014, the NHPUC approved a one year decrease to distribution rates of $1.3 million, effective July 1, 2014.


ES and SCRC Rates:  On December 15, 2014, PSNH updated its request with the NHPUC to adjust its ES and SCRC rates effective January 1, 2015.  PSNH's update proposed to increase the current ES and SCRC billing rates to reflect projected costs for 2015.  On December 29, 2014, the NHPUC approved the request. The approved energy supply portion of the 2015 rate is 10.56 cents per kWh and the SCRC rate for 2015 is 0.110 cents per kWh.


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, pursuant to state law, 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 remains 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 prudence hearings in October 2014.  On December 26, 2014, PSNH requested that the NHPUC stay this proceeding in order to allow discussions to take place with other significant parties to determine whether a collaborative resolution of all issues was achievable.  The New Hampshire Governor and Senate Majority Leader expressed support for this effort.  On January 15, 2015, the NHPUC issued an order granting the motion to stay in this proceeding, and settlement discussions have ensued.


While we cannot predict with certainty the outcome of the Clean Air Project prudence review, we believe all costs were incurred appropriately and continue to remain probable of recovery.


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.  The NHPUC accepted from the NHPUC Staff a "Report on Investigation into Market Conditions, Default Service Rate, Generation Ownership and Impact on the Competitive Electricity Market."  The report recommended that the NHPUC examine whether default service rates remain sustainable on a going forward basis, define "just and reasonable" with respect to default service in the context of competitive retail markets, analyze the current and expected value of PSNH's generating units, and identify means to mitigate and address stranded cost recovery.  


In 2013, the NHPUC issued a Request for Proposal to hire a valuation expert to determine the market value of PSNH's generation assets and entitlements.  The State of New Hampshire Legislative Oversight Committee on Electric Utility Restructuring (Oversight Committee) requested that the NHPUC conduct an analysis to determine whether it is now in the economic interest of PSNH's retail customers for PSNH to divest its interest in generation plants.  The Oversight Committee asked for a preliminary report on the findings by April 1, 2014 that would include at a minimum the NHPUC Staff's position, the analysis of the valuation expert, and any recommendations for legislation that may be needed concerning divestiture or otherwise related to this issue.    


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" of approximately $435 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 the 2014 Legislative 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 required 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.  A progress report from the NHPUC must be provided to the Oversight Committee by March 31, 2015.  The law gives the NHPUC express authority



40


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 remain probable of recovery.


Legislative and Policy Matters


Federal:


On December 19, 2014, the "Tax Increase Prevention Act of 2014" became law, which extended the accelerated deduction of depreciation to businesses through 2014.  This extended stimulus provides NU with cash flow benefits of approximately $200 million (approximately $70 million at CL&P) in 2015.  


Massachusetts:


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.  On October 31, 2014, NSTAR Gas filed the GSEP with the DPU.  We expect a decision on the program in April 2015.


Critical Accounting Policies


The preparation of financial statements in conformity with GAAP requires management to make estimates, assumptions and, at times, difficult, subjective or complex judgments.  Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact our financial position, results of operations or cash flows.  Our management communicates to and discusses with the Audit Committee of our Board of Trustees significant matters relating to critical accounting policies.  Our critical accounting policies are discussed below.  See the combined notes to our financial statements for further information concerning the accounting policies, estimates and assumptions used in the preparation of our financial statements.  


Regulatory Accounting:  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.


The application of accounting guidance for rate-regulated enterprises results in recording regulatory assets and liabilities.  Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates.  Regulatory assets are amortized as the incurred costs are recovered through customer rates.  In some cases, we record regulatory assets before approval for recovery has been received from the applicable regulatory commission.  We must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery.  We base our conclusion on certain factors, including, but not limited to, regulatory precedent.  Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or probable future refunds to customers.


We use our best judgment when recording regulatory assets and liabilities; however, regulatory commissions can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on our financial statements.  We believe it is probable that the Regulated companies will recover the regulatory assets that have been recorded.  If we determined that we could no longer apply the accounting guidance applicable to rate-regulated enterprises to our operations, or that we could not conclude that it is probable that costs would be recovered from customers in future rates, the costs would be charged to earnings in the period in which the determination is made.


Unbilled Revenues:  The determination of retail energy sales to residential, commercial and industrial customers is based on the reading of meters, which occurs regularly throughout the month.  Billed revenues are based on these meter readings, and the majority of recorded annual revenues is based on actual billings.  Because customers are billed throughout the month based on pre-determined cycles rather than on a calendar month basis, an estimate of electricity or natural gas delivered to customers for which the customers have not yet been billed is calculated as of the balance sheet date.


Unbilled revenues represent an estimate of electricity or natural gas delivered to customers but not yet billed.  Unbilled revenues are included in Operating Revenues on the statement of income and are assets on the balance sheet that are reclassified to Accounts Receivable in the following month as customers are billed.  Such estimates are subject to adjustment when actual meter readings become available, when there is a change in estimates and under other circumstances.  


The Regulated companies estimate unbilled sales monthly using the daily load cycle method.  The daily load cycle method allocates billed sales to the current calendar month based on the daily load for each billing cycle.  The billed sales are subtracted from total month load, net of delivery losses, to estimate unbilled sales.  Unbilled revenues are estimated by first allocating unbilled sales to the respective customer classes, then applying an estimated rate by customer class to those sales.  The estimate of unbilled revenues is sensitive to numerous factors, such as energy demands, weather and changes in the composition of customer classes that can significantly impact the amount of revenues recorded.  




41


Pension and PBOP:  We sponsor Pension and PBOP Plans to provide retirement benefits to our employees.  Effective January 1, 2015, the two Pension Plans were merged into one Pension Plan, sponsored by NUSCO, and the PBOP Plans were merged into one PBOP Plan, sponsored by NUSCO.  For each of these plans, several significant assumptions are used to determine the projected benefit obligation, funded status and net periodic benefit cost.  These assumptions include the expected long-term rate of return on plan assets, discount rate, compensation/progression rate, mortality assumptions, and health care cost trend rates.  We evaluate these assumptions at least annually and adjust them as necessary.  Changes in these assumptions could have a material impact on our financial position, results of operations or cash flows.  


Pre-tax net periodic benefit expense (excluding SERP) for the Pension Plans was $118.4 million, $236.3 million and $234.9 million for the years ended December 31, 2014, 2013 and 2012, respectively.  The pre-tax net periodic benefit expense for the PBOP Plans was $8.1 million, $32.6 million and $72.3 million for the years ended December 31, 2014, 2013 and 2012, respectively.  NSTAR Pension and PBOP expense was included in NU beginning April 10, 2012.


Expected Long-Term Rate of Return on Plan Assets:  In developing this assumption, we consider historical and expected returns and input from our consultants.  Our expected long-term rate of return on assets is based on assumptions regarding target asset allocations and corresponding expected rates of return for each asset class.  We routinely review the actual asset allocations and periodically rebalance the investments to the targeted asset allocations when appropriate.  For the year ended December 31, 2014, our aggregate expected long-term rate of return assumption of 8.25 percent was used to determine our Pension and PBOP expense.  For the forecasted 2015 Pension and PBOP expense, our expected long-term rate of return of 8.25 percent for all plans was used reflecting our target asset allocations.


Discount Rate:  Payment obligations related to the Pension and PBOP Plans are discounted at interest rates applicable to the expected timing of each plan's cash flows.  The discount rate that is utilized in determining the Pension and PBOP obligations is based on a yield-curve approach.  This approach is based on a population of bonds with an average rating of AA based on bond ratings by Moody's, S&P and Fitch, and uses bonds with above median yields within that population.  As of December 31, 2014, the discount rates used to determine the funded status were 4.2 percent for the Pension Plans and 4.22 percent for the PBOP Plans.  As of December 31, 2013, the discount rates used were 5.03 percent for the NUSCO Pension Plan, 4.85 percent for the NSTAR Pension Plan, 4.78 percent for the NUSCO PBOP Plans and 5.10 percent for the NSTAR PBOP Plan.  As of December 31, 2014, the decreases in the discount rates resulted in an increase on NU’s funded status liability of approximately $530 million and $110 million for the Pension and PBOP Plans, respectively.


Compensation/Progression Rate:  This assumption reflects the expected long-term salary growth rate, including consideration of the levels of increases built into collective bargaining agreements, and impacts the estimated benefits that Pension Plan participants receive in the future.  As of December 31, 2014, the compensation/progression rate used to determine the funded status was 3.5 percent.  


Mortality Assumptions:  Assumptions as to mortality of the participants in our Pension and PBOP Plans are a key estimate in measuring the expected payments a participant may receive over their lifetime and the plan liability we need to record.  During 2014, the Society of Actuaries released a series of updated mortality tables resulting from recent studies that measured mortality rates for various groups of individuals.  The updated mortality tables released in 2014 reflect increased life expectancy of plan participants by 3 to 5 years and have the effect of increasing the estimate of benefits to be provided to plan participants.  As of December 31, 2014, the impact of this adoption on NU’s funded status was an increase in the liability of approximately $340 million and $82 million for the Pension and PBOP Plans, respectively.


Actuarial Determination of Expense:  Pension and PBOP expense is determined by our actuaries and consists of service cost and prior service cost, interest cost based on the discounting of the obligations, amortization of actuarial gains and losses and amortization of the net transition obligation (which was fully amortized in 2013), offset by the expected return on plan assets.  Actuarial gains and losses represent differences between assumptions and actual information or updated assumptions.


Effective January 1, 2015, as a result of the merger of the NUSCO Pension and PBOP plans into the respective NSTAR plans, the NSTAR accounting policies became effective for the NUSCO plans.  For the NSTAR Pension and PBOP plans, we apply a corridor approach to determine the potential actuarial gain or loss to be amortized in the Pension and PBOP net periodic benefit expense.  This amortization approach is applied if the unrecognized actuarial gains or losses exceed 10 percent of the greater of the fair value of plan assets or the projected benefit obligation.  This excess is amortized over the average remaining service period of active plan participants.  In addition, for the NSTAR plans, the expected return on plan assets is determined by applying the assumed long-term rate of return to the Pension and PBOP Plan asset balances.  This calculated expected return is compared to the actual return or loss on plan assets at the end of each year to determine the investment gains or losses to be immediately reflected in actuarial gains and losses.  For the years ended December 31, 2014, 2013 and 2012, the NUSCO Pension and PBOP plans did not utilize the corridor approach, and the expected return on plan assets was determined by applying our assumed long-term rate of return to a four-year rolling average of plan asset fair values.  This calculation recognized investment gains or losses over a four-year period from the years in which they occurred.  


Forecasted Expenses and Expected Contributions:  We estimate that the expense for the Pension and PBOP Plans will be approximately $130 million and $4 million, respectively, in 2015.  Pension and PBOP expense for subsequent years will depend on future investment performance, changes in future discount rates and other assumptions, and various other factors related to the populations participating in the plans.  Pension and PBOP expense charged to earnings is net of the amounts capitalized.  


Our policy is to annually fund the Pension Plans in an amount at least equal to the amount that will satisfy federal requirements.  We contributed $171.6 million to the Pension Plans in 2014, of which $101 million was contributed by NSTAR Electric.  We currently estimate approximately $155 million of contributions to the Pension Plan in 2015.  


For the PBOP Plans, it is our policy to annually fund the PBOP Plans up to the maximum tax-deductible level permitted.  We contributed $40 million to the PBOP Plans in 2014.  We currently estimate approximately $27 million in contributions to the PBOP Plan in 2015.




42


Sensitivity Analysis:  The following represents the hypothetical increase to the Pension Plans' (excluding SERP) and PBOP Plans' reported annual cost as a result of a change in the following assumptions by 50 basis points:


 

 

Increase in Pension Plan Cost

 

Increase in PBOP Plan Cost

(Millions of Dollars)

 

As of December 31,

Assumption Change

 

 

2014

 

 

2013

 

2014

 

2013

NU

 

 

 

 

 

 

 

 

 

 

 

 

Lower expected long-term rate of return

 

$

19.3 

 

$

17.2 

 

$

4.0 

 

$

3.4 

Lower discount rate

 

$

19.1 

 

$

22.3 

 

$

2.2 

 

$

6.8 

Higher compensation rate

 

$

10.2 

 

$

12.4 

 

 

N/A 

 

 

 N/A 


Health Care Cost:  As of December 31, 2014, the health care cost trend rate assumption used to determine the PBOP Plans' year end funded status was 6.5 percent, subsequently decreasing to an ultimate rate of 4.5 percent in 2023. The effect of a hypothetical increase in the health care cost trend rate by one percentage point would be an increase to the service and interest cost components of PBOP Plan expense by $5.3 million in 2014, and a $111.2 million increase to the PBOP obligation.  


Goodwill:  We have recorded approximately $3.5 billion of goodwill associated with previous mergers and acquisitions. We have identified our reporting units for purposes of allocating and testing goodwill as Electric Distribution, Electric Transmission and Natural Gas Distribution.  These reporting units are consistent with our operating segments underlying our reportable segments.  Electric Distribution and Electric Transmission reporting units include carrying values for the respective components of CL&P, NSTAR Electric, PSNH and WMECO.  The Natural Gas Distribution reporting unit includes the carrying values of NSTAR Gas and Yankee Gas.  As of December 31, 2014, goodwill was allocated to the reporting units as follows:  $2.5 billion to Electric Distribution, $0.6 billion to Electric Transmission, and $0.4 billion to Natural Gas Distribution.


We are required to test goodwill balances for impairment at least annually by considering the fair values of the reporting units, which requires us to use estimates and judgments.  We have selected October 1st of each year as the annual goodwill impairment testing date.  Goodwill impairment is deemed to exist if the carrying value of a reporting unit exceeds its estimated fair value and if the implied fair value of goodwill based on the estimated fair values of the reporting units' assets and liabilities is less than the carrying amount of the goodwill.  If goodwill were deemed to be impaired, it would be written down in the current period to the extent of the impairment.  


We performed an impairment test of goodwill as of October 1, 2014 for the Electric Distribution, Electric Transmission and Natural Gas Distribution reporting units.  This evaluation required the test of several factors that impact the fair value of the reporting units, including conditions and assumptions that affect the future cash flows of the reporting units.  The 2014 goodwill impairment test resulted in a conclusion that goodwill is not impaired and none of the reporting units is at risk of a goodwill impairment.  


Income Taxes:  Income tax expense is estimated annually for each of the jurisdictions in which we operate.  This process involves estimating current and deferred income tax expense or benefit and the impact of temporary differences resulting from differing treatment of items for financial reporting and income tax return reporting purposes.  Such differences are the result of timing of the deduction for expenses, as well as any impact of permanent differences, non-tax deductible expenses, or other items, including items that directly impact our tax return as a result of a regulatory activity (flow-through items).  The temporary differences and flow-through items result in deferred tax assets and liabilities that are included in the balance sheets.  The income tax estimation process impacts all of our segments.  We record income tax expense quarterly using an estimated annualized effective tax rate.  


We also account for uncertainty in income taxes, which applies to all income tax positions previously filed in a tax return and income tax positions expected to be taken in a future tax return that have been reflected on our balance sheets.  The determination of whether a tax position meets the recognition threshold under applicable accounting guidance is based on facts and circumstances available to us.  Once a tax position meets the recognition threshold, the tax benefit is measured using a cumulative probability assessment.  Assigning probabilities in measuring a recognized tax position and evaluating new information or events in subsequent periods requires significant judgment and could change previous conclusions used to measure the tax position estimate.  New information or events may include tax examinations or appeals (including information gained from those examinations), developments in case law, settlements of tax positions, changes in tax law and regulations, rulings by taxing authorities and statute of limitation expirations.  Such information or events may have a significant impact on our financial position, results of operations and cash flows.  


Accounting for Environmental Reserves:  Environmental reserves are accrued when assessments indicate it is probable that a liability has been incurred and an amount can be reasonably estimated.  Adjustments made to estimates of environmental liabilities could have a significant impact on earnings.  We estimate these liabilities based on findings through various phases of the assessment, considering the most likely action plan from a variety of available remediation options (ranging from no action required to full site remediation and long-term monitoring), current site information from our site assessments, remediation estimates from third party engineering and remediation contractors, and our prior experience in remediating contaminated sites.  If a most likely action plan cannot yet be determined, we estimate the liability based on the low end of a range of possible action plans.  Our estimates incorporate currently enacted state and federal environmental laws and regulations and data released by the EPA and other organizations.  The estimates associated with each possible action plan are judgmental in nature partly because there are usually several different remediation options from which to choose.  Our estimates are subject to revision in future periods based on actual costs or new information from other sources, including the level of contamination at the site, the extent of our responsibility or the extent of remediation required, recently enacted laws and regulations or a change in cost estimates due to certain economic factors.  


Fair Value Measurements:  We follow fair value measurement guidance that defines fair value as the price that would be received for the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price).  We have applied this guidance to our Company's derivative contracts that are not elected or designated as "normal purchases or normal sales" (normal), to marketable securities held in trusts, our valuations of investments in our Pension and PBOP Plans, and nonrecurring fair value measurements of nonfinancial assets such as goodwill and AROs.  




43


Changes in fair value of the Regulated company derivative contracts are recorded as Regulatory Assets or Liabilities, as we recover the costs of these contracts in rates charged to customers.  These valuations are sensitive to the prices of energy and energy-related products in future years for which markets have not yet developed and assumptions are made.  


We use quoted market prices when available to determine fair values of financial instruments.  If quoted market prices are not available, fair value is determined using quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments that are not active and model-derived valuations.  When quoted prices in active markets for the same or similar instruments are not available, we value derivative contracts using models that incorporate both observable and unobservable inputs.  Significant unobservable inputs utilized in the models include energy and energy-related product prices for future years for long-dated derivative contracts and market volatilities.  Discounted cash flow valuations incorporate estimates of premiums or discounts, reflecting risk adjusted profit that would be required by a market participant to arrive at an exit price, using available historical market transaction information.  Valuations of derivative contracts also reflect our estimates of nonperformance risk, including credit risk.  


Other Matters


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


Contractual Obligations and Commercial Commitments:  Information regarding our contractual obligations and commercial commitments as of December 31, 2014 is summarized annually through 2019 and thereafter as follows:


NU

 

(Millions of Dollars)

 

2015

 

2016

 

2017

 

2018

 

2019

 

Thereafter

 

Total

Long-term debt maturities (a)

 

$

216.7 

 

$

200.0 

 

$

745.0 

 

$

810.0 

 

$

800.0 

 

$

4,956.6 

 

$

7,728.3 

Estimated interest payments on existing debt (b)

 

 

336.5 

 

 

330.7 

 

 

326.2 

 

 

273.9 

 

 

246.2 

 

 

2,502.3 

 

 

4,015.8 

Capital leases (c)

 

 

2.4 

 

 

2.2 

 

 

2.1 

 

 

2.1 

 

 

2.0 

 

 

3.5 

 

 

14.3 

Operating leases (d)

 

 

20.1 

 

 

17.6 

 

 

14.6 

 

 

10.5 

 

 

8.6 

 

 

22.5 

 

 

93.9 

Funding of pension obligations (d) (e)

 

 

154.6 

 

 

146.2 

 

 

145.4 

 

 

76.0 

 

 

15.0 

 

 

N/A 

 

 

537.2 

Funding of PBOP obligations (d)

 

 

26.5 

 

 

27.9 

 

 

26.3 

 

 

7.1 

 

 

4.1 

 

 

4.5 

 

 

96.4 

Estimated future annual long-term contractual costs (f)

 

 

685.8 

 

 

598.2 

 

 

421.6 

 

 

327.6 

 

 

290.0 

 

 

2,198.4 

 

 

4,521.6 

Total (g)

 

$

1,442.6 

 

$

1,322.8 

 

$

1,681.2 

 

$

1,507.2 

 

$

1,365.9 

 

$

9,687.8 

 

$

17,007.5 


CL&P

 

(Millions of Dollars)

 

2015

 

2016

 

2017

 

2018

 

2019

 

Thereafter

 

Total

Long-term debt maturities (a)

 

$

162.0 

 

$

 

$

250.0 

 

$

300.0 

 

$

250.0 

 

$

1,640.3 

 

$

2,602.3 

Estimated interest payments on existing debt (b)

 

 

129.0 

 

 

126.5 

 

 

122.5 

 

 

104.2 

 

 

88.8 

 

 

1,138.8 

 

 

1,709.8 

Capital leases (c)

 

 

2.0 

 

 

1.9 

 

 

2.0 

 

 

2.0 

 

 

2.0 

 

 

3.5 

 

 

13.4 

Operating leases (d)

 

 

4.3 

 

 

3.8 

 

 

2.6 

 

 

1.5 

 

 

1.1 

 

 

4.0 

 

 

17.3 

Funding of pension obligations (d) (e)

 

 

 

 

0.8 

 

 

19.7 

 

 

18.4 

 

 

4.3 

 

 

N/A 

 

 

43.2 

Estimated future annual long-term contractual costs (f)

 

 

233.4 

 

 

241.8 

 

 

169.1 

 

 

123.4 

 

 

106.4 

 

 

779.7 

 

 

1,653.8 

Total (g)

 

$

530.7 

 

$

374.8 

 

$

565.9 

 

$

549.5 

 

$

452.6 

 

$

3,566.3 

 

$

6,039.8 


(a)

Long-term debt maturities exclude the spent nuclear fuel obligation, net unamortized premiums and discounts, and other fair value adjustments.


(b)

Estimated interest payments on fixed-rate debt are calculated by multiplying the coupon rate on the debt by its scheduled notional amount outstanding for the period of measurement.  Estimated interest payments on floating-rate debt are calculated by multiplying the end of 2014 floating-rate reset on the debt by its scheduled notional amount outstanding for the period of measurement.  This same rate is then assumed for the remaining life of the debt.  


(c)

The capital lease obligations include interest.


(d)

Amounts are not included on our balance sheets.  


(e)

These amounts represent NU's estimated minimum pension contributions to its qualified Pension Plans required under federal legislation.  Contributions in 2016 through 2019 and thereafter will vary depending on many factors, including the performance of existing plan assets, valuation of the plan's liabilities and long-term discount rates, and are subject to change.   


(f)

Other than certain derivative contracts held by the Regulated companies, these obligations are not included on our balance sheets.  


(g)

Does not include other long-term liabilities recorded on our balance sheet, such as environmental reserves, employee medical insurance, workers compensation and long-term disability insurance reserves, ARO liability reserves and other reserves, as we cannot make reasonable estimates of the timing of payments.  Also does not include an NU contingent commitment not included on our balance sheets of approximately $30 million to an energy investment fund, which would be invested under certain conditions, as we cannot make reasonable estimates of the periods or the investment contributions.  


For further information regarding our contractual obligations and commercial commitments, see Note 6, "Asset Retirement Obligations,"  Note 7, "Short-Term Debt," Note 8, "Long-Term Debt," Note 9A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pensions," Note 11, "Commitments and Contingencies," and Note 12, "Leases," to the financial statements.




44


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 years ended December 31, 2014, 2013, and 2012 included in this Annual Report on Form 10-K.  The year ended December 31, 2012 amounts include the operations of NSTAR beginning April 10, 2012.


Comparison of 2014 to 2013:


 

 

 

For the Years Ended December 31,

 

 

 

 

 

 

 

 

 

 

Increase/

 

 

 

(Millions of Dollars)

2014 

2013 

(Decrease)

Percent

 

Operating Revenues

$

 7,741.9 

 

$

 7,301.2 

 

$

 440.7 

 

 6.0 

%

Operating Expenses:

 

 

 

 

 

 

 

 

 

 

 

 

Purchased Power, Fuel and Transmission

 

 3,021.6 

 

 

 2,483.0 

 

 

 538.6 

 

 21.7 

 

 

Operations and Maintenance

 

 1,427.6 

 

 

 1,515.0 

 

 

 (87.4)

 

 (5.8)

 

 

Depreciation

 

 614.7 

 

 

 610.8 

 

 

 3.9 

 

 0.6 

 

 

Amortization of Regulatory Assets, Net

 

 10.7 

 

 

 206.3 

 

 

 (195.6)

 

 (94.8)

 

 

Amortization of Rate Reduction Bonds

 

 - 

 

 

 42.6 

 

 

 (42.6)

 

 (100.0)

 

 

Energy Efficiency Programs

 

 473.1 

 

 

 401.9 

 

 

 71.2 

 

 17.7 

 

 

Taxes Other Than Income Taxes

 

 561.4 

 

 

 512.2 

 

 

 49.2 

 

 9.6 

 

 

 

Total Operating Expenses

 

 6,109.1 

 

 

 5,771.8 

 

 

 337.3 

 

 5.8 

 

Operating Income

 

 1,632.8 

 

 

 1,529.4 

 

 

 103.4 

 

 6.8 

 

Interest Expense

 

 362.1 

 

 

 338.7 

 

 

 23.4 

 

 6.9 

 

Other Income, Net

 

 24.6 

 

 

 29.9 

 

 

 (5.3)

 

 (17.7)

 

Income Before Income Tax Expense

 

 1,295.3 

 

 

 1,220.6 

 

 

 74.7 

 

 6.1 

 

Income Tax Expense

 

 468.3 

 

 

 426.9 

 

 

 41.4 

 

 9.7 

 

Net Income

 

 827.0 

 

 

 793.7 

 

 

 33.3 

 

 4.2 

 

Net Income Attributable to Noncontrolling Interests

 

 7.5 

 

 

 7.7 

 

 

 (0.2)

 

 (2.6)

 

Net Income Attributable to Controlling Interest

$

 819.5 

 

$

 786.0 

 

$

 33.5 

 

 4.3 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

 

 

 

 

 

For the Years Ended December 31,

 

 

 

 

 

 

 

 

 

 

Increase /

 

 

 

(Millions of Dollars)

2014 

2013 

(Decrease)

Percent

 

Electric Distribution

$

 5,663.4 

 

$

 5,362.3 

 

$

 301.1 

 

 5.6 

%

Natural Gas Distribution

 

 1,007.3 

 

 

 855.8 

 

 

 151.5 

 

 17.7 

 

Transmission

 

 1,018.2 

 

 

 978.7 

 

 

 39.5 

 

 4.0 

 

Other and Eliminations

 

 53.0 

 

 

 104.4 

 

 

 (51.4)

 

 (49.2)

 

Total Operating Revenues

$

 7,741.9 

 

$

 7,301.2 

 

$

 440.7 

 

 6.0 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Years Ended December 31,

 

 

 

 

 

 

 

 

 

 

Increase/

 

 

 

 

2014 

2013 

(Decrease)

Percent

 

Retail Electric Sales Volumes in GWh

 

 54,442 

 

 

 55,331 

 

 

 (889)

 

 (1.6)

%

Firm Natural Gas Sales Volumes in Million Cubic Feet

 

 104,191 

 

 

 98,258 

 

 

 5,933 

 

 6.0 

 


Operating Revenues increased $440.7 million in 2014 compared to 2013.  


The most significant factor in the increase in revenues relates to cost tracking mechanisms for the recovery of higher costs associated with the procurement of energy supply, which increased $506.8 million and $126.9 million for electric distribution and natural gas distribution, respectively.  These costs were impacted by the overall New England wholesale energy supply market in which higher natural gas delivery costs had an adverse impact on the cost of electric energy purchased for our retail electric customers and the cost of natural gas purchased on behalf of our retail natural gas customers.  Energy supply costs are recovered from customers in rates through cost tracking mechanisms and therefore have no impact on earnings.  These costs and related recovery impacts were partially offset by decreases in transition cost recovery revenues, which are recovered through cost tracking mechanisms, reflecting the full collection in 2013 of previously deferred costs, as well as the full amortization of RRBs.  


Firm base natural gas distribution revenues increased $26.3 million in 2014, as compared to 2013, which reflected a 6 percent increase in firm natural gas sales volumes.  The increase in sales volumes was driven primarily by the colder winter weather experienced throughout our service territories in the first quarter of 2014.  The weather conditions experienced were significantly colder than both normal and the same period last year throughout New England and our service territories in Connecticut and Massachusetts.  Weather-normalized total firm natural gas sales volumes (based on 30-year average temperatures) increased 2.9 percent in 2014, as compared to 2013, due primarily to residential and commercial customer growth.


Base electric distribution revenues decreased $12.1 million in 2014 compared to 2013. This reflected the impact of a 1.6 percent decrease in retail electric sales volumes.  The decrease in sales volumes was driven primarily by the cooler summer weather in 2014 compared to 2013, as well as the impact of our utility-sponsored energy efficiency programs.  Weather-normalized retail electric sales volumes decreased 1 percent in 2014, as compared to 2013, reflecting the impact of our utility-sponsored energy efficiency programs.  The negative sales volume impact was partially offset by the impact of CL&P's base distribution rate increase effective December 1, 2014.  




45


CL&P and NSTAR Electric recognized lost base revenue (LBR) related to reductions in sales volume as a result of energy efficiency.  LBR is recovered from retail distribution customers.  Including the impact from the recognition of LBR, base distribution revenues increased in 2014, as compared to 2013.  We recognized $45.2 million of LBR in 2014, compared to $20.3 million in 2013.  Effective December 1, 2014, CL&P no longer recognizes LBR due to its revenue decoupling mechanism, which, similar to WMECO's revenue decoupling mechanism, provides a base amount of distribution revenues ($1.041 billion on an annual basis) that effectively breaks the relationship between revenues and customer electricity usage.  The revenue decoupling mechanism is designed to allow each of CL&P and WMECO to encourage energy efficiency for its customers without negatively impacting its revenues.


Transmission revenues increased $39.5 million in 2014, as compared to 2013, due primarily to the recovery of higher revenue requirements associated with ongoing investments in our transmission infrastructure.  This increase was partially offset by the impact of the $37 million net reserve recorded in 2014 as a result of the 2014 FERC ROE orders, compared to the $23.7 million reserve recorded in 2013 for the FERC ALJ initial decision in the FERC base ROE complaints.  


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 reconciling cost tracking mechanisms, which have no impact on earnings (tracked costs).  Purchased Power, Fuel and Transmission increased in 2014, as compared to 2013, due primarily to the following:


(Millions of Dollars)

Increase/(Decrease)

Electric Distribution

$

458.2 

Natural Gas Distribution

 

104.1 

Transmission

 

(2.8)

Other and Eliminations

 

(20.9)

Total Purchased Power, Fuel and Transmission

$

538.6 


The increase in purchased power, fuel and transmission at the electric and natural gas distribution businesses were driven by the higher costs associated with the procurement of energy supply.  As a result of increases in the New England wholesale energy supply market for both electricity and natural gas, the costs incurred to purchase energy on behalf of our customers were significantly higher in 2014 compared to 2013.  Our energy supply costs were impacted by higher natural gas delivery costs, which had an adverse impact on the cost of electric energy purchased for our retail electric customers and the cost of natural gas purchased on behalf of our retail natural gas customers.  


Operations and Maintenance expense includes tracked costs and costs that are recovered through base electric and natural gas distribution rates, which therefore impact earnings (non-tracked costs).  Operations and Maintenance decreased in 2014, as compared to 2013, due primarily to the following:


(Millions of Dollars)

Increase/(Decrease)

Base Electric Distribution:

 

 

   Labor and other employee-related costs, including pension costs

$

(77.3)

   Implementation of a new outage restoration program at CL&P

 

9.2 

   Storm restoration costs

 

(11.4)

   All other operations and maintenance

 

(29.4)

Total Base Electric Distribution

 

(108.9)

Total Base Natural Gas Distribution

 

(0.9)

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

 

16.6 

Total Distribution and Transmission

 

(93.2)

Other and eliminations:

 

 

  Integration and severance costs

 

13.3 

  All other (including eliminations)

 

(7.5)

Total Operations and Maintenance

$

(87.4)


Depreciation increased in 2014, as compared to 2013, due primarily to an increase related to higher utility plant balances resulting from completed construction projects placed into service ($34.5 million), partially offset by a decrease in the CYAPC and YAEC decommissioning costs, which do not impact earnings ($30.6 million).


Amortization of Regulatory Assets, 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, Net, decreased in 2014, as compared to 2013, due primarily to the following:


(Millions of Dollars)

Increase/(Decrease)

NSTAR Electric (primarily recovery of transition costs)

$

(236.4)

PSNH (primarily default energy service charge)

 

(9.2)

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

 

54.4 

WMECO (primarily recovery of transition costs)

 

(3.0)

Other

 

(1.4)

Total Amortization of Regulatory Assets, Net

$

(195.6)


Amortization of Rate Reduction Bonds decreased in 2014, as compared to 2013, due to the maturity in 2013 of RRBs of NSTAR Electric, PSNH and WMECO.




46


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


Taxes Other Than Income Taxes increased in 2014, as compared to 2013, due primarily to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates.


Interest Expense increased in 2014, as compared to 2013, due primarily to lower interest income related to a decrease in the recovery of previously deferred transition costs ($9.9 million), an increase in interest on long-term debt ($4 million) as a result of new debt issuances in 2014 and the absence in 2014 of the favorable impact from the resolution of a Connecticut state income tax audit in 2013.


Other Income, Net decreased in 2014, as compared to 2013, due primarily to lower unrealized gains on the assets supporting the deferred compensation plans ($13 million), and the absence in 2014 of an insurance policy claim received in 2013 ($1.5 million), partially offset by higher AFUDC related to equity funds ($6.6 million), and a net gain on the sale of land ($4.5 million).


Income Tax Expense increased in 2014, as compared to 2013, due primarily to higher pre-tax earnings ($26.1 million), and higher state taxes and various other impacts ($15.3 million).  The higher state taxes include a net reduction in the valuation allowance for state tax positions, which is based on the most recent available data.


Comparison of 2013 to 2012:


 

 

 

Operating Revenues and Expenses

 

 

For the Years Ended December 31,

 

(Millions of Dollars)

2013 

 

2012 (a)

 

Increase/

 

Percent

 

(Decrease)

 

Operating Revenues

$

 7,301.2 

 

$

 6,273.8 

 

$

 1,027.4 

 

 16.4 

%

Operating Expenses:

 

 

 

 

 

 

 

 

 

 

 

 

Purchased Power, Fuel and Transmission

 

 2,483.0 

 

 

 2,084.4 

 

 

 398.6 

 

 19.1 

 

 

Operations and Maintenance

 

 1,515.0 

 

 

 1,583.1 

 

 

 (68.1)

 

 (4.3)

 

 

Depreciation

 

 610.8 

 

 

 519.0 

 

 

 91.8 

 

 17.7 

 

 

Amortization of Regulatory Assets, Net

 

 206.3 

 

 

 79.8 

 

 

 126.5 

 

(b)

 

 

Amortization of Rate Reduction Bonds

 

 42.6 

 

 

 142.0 

 

 

 (99.4)

 

 (70.0)

 

 

Energy Efficiency Programs

 

 401.9 

 

 

 313.1 

 

 

 88.8 

 

 28.4 

 

 

Taxes Other Than Income Taxes

 

 512.2 

 

 

 434.2 

 

 

 78.0 

 

 18.0 

 

 

 

Total Operating Expenses

 

 5,771.8 

 

 

 5,155.6 

 

 

 616.2 

 

 12.0 

 

Operating Income

$

 1,529.4 

 

$

 1,118.2 

 

$

 411.2 

 

 36.8 

%


(a)

The 2012 results include the operations of NSTAR beginning April 10, 2012.  

(b)

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


Operating Revenues

 

 

 

For the Years Ended December 31,

 

(Millions of Dollars)

2013 

 

2012 (a)

 

Increase/
(Decrease)

 

Percent

 

Electric Distribution

$

 5,362.3 

 

$

 4,716.5 

 

$

 645.8 

 

 13.7 

%

Natural Gas Distribution

 

 855.8 

 

 

 572.9 

 

 

 282.9 

 

 49.4 

 

 

Total Distribution

 

 6,218.1 

 

 

 5,289.4 

 

 

 928.7 

 

 17.6 

 

Transmission

 

 978.7 

 

 

 861.5 

 

 

 117.2 

 

 13.6 

 

 

Total Regulated Companies

 

 7,196.8 

 

 

 6,150.9 

 

 

 1,045.9 

 

 17.0 

 

Other and Eliminations

 

 104.4 

 

 

 122.9 

 

 

 (18.5)

 

 (15.1)

 

Total Operating Revenues

$

 7,301.2 

 

$

 6,273.8 

 

$

 1,027.4 

 

 16.4 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

The 2012 results include the operations of NSTAR beginning April 10, 2012.  


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

 

 

 

For the Years Ended December 31,

 

 

 

2013 

 

2012 (a)

 

Increase

 

Percent

 

Retail Electric Sales in GWh

 55,331 

 

 54,808 

 

 523 

 

 1.0 

%

Firm Natural Gas Sales in Million Cubic Feet

 98,258 

 

 87,527 

 

 10,731 

 

 12.3 

 


(a)

Results include retail electric sales of NSTAR Electric and the firm natural gas sales of NSTAR Gas from January 1, 2012 through December 31, 2012 for comparative purposes only.




47


Our Operating Revenues increased in 2013, as compared to 2012, due primarily to the addition of NSTAR's operations.  During the first quarter of 2013, the former operating subsidiaries of NSTAR contributed approximately $800 million of operating revenues.  Absent the first quarter 2013 NSTAR operating revenues, our Operating Revenues increased approximately $227 million, as compared to 2012, due primarily to:  


·

A $62.5 million increase in transmission revenues, net of applicable eliminations, as a result of the recovery of higher transmission expenses and continuing investments in our transmission infrastructure.  The increase was partially offset by the establishment of a reserve related to the FERC ALJ initial decision in the third quarter of 2013.


·

A $34.3 million increase in base electric distribution revenues, net of applicable eliminations, reflecting an increase of approximately 1 percent in retail electric sales.  The increase in sales volumes was driven primarily by the colder winter weather experienced throughout our service territories in early and late 2013.  In addition, the increase in revenues resulted from the NHPUC-approved distribution rate increases at PSNH effective July 1, 2012 and July 1, 2013 as a result of the 2010 distribution rate case settlement.  These positive impacts on revenue were partially offset by the impact of our utility-sponsored energy efficiency programs.


·

A $28.8 million increase in firm natural gas distribution revenues.  This increase was driven by the colder winter weather in early and late 2013, residential customer growth, an increase in natural gas conversions, the migration of interruptible customers switching to firm service rates and the addition of gas-fired distributed generation.


·

The remaining increase was due primarily to higher revenues from increases related to our fully reconciling cost recovery mechanisms (tracked costs) related to the recovery of energy supply, retail transmission and utility-sponsored energy efficiency programs.  Revenues related to cost recovery mechanisms vary from period to period based on the timing of collections of the costs incurred.  These revenues do not result in an impact on earnings.  


Purchased Power, Fuel and Transmission increased in 2013, as compared to 2012, due primarily to the following:


(Millions of Dollars)

Increase/(Decrease)

The addition of NSTAR's operations

$

 321.4 

Transmission segment costs

 

 70.8 

Firm natural gas sales related costs

 

 42.0 

Partially offset by:

 

 

Electric distribution segment fuel and energy supply costs

 

 (13.9)

CfDs and capacity contracts

 

 (12.0)

All other items

 

 (9.7)

 

 

$

 398.6 


Operations and Maintenance decreased in 2013, as compared to 2012, due primarily to the following:


(Millions of Dollars)

Increase/(Decrease)

The addition of NSTAR's operations

$

 123.6 

Partially offset by:

 

 

  Integration, merger and settlement agreement costs

 

 (150.3)

  NU's unregulated contracting business costs

 

 (17.4)

  General and administrative costs

 

 (12.9)

  Transmission segment costs

 

 (5.2)

  Natural gas segment costs

 

 10.5 

  Electric distribution segment costs

 

 1.3 

  All other items

 

 (17.7)

 

$

 (68.1)


Depreciation increased in 2013, as compared to 2012, due primarily to the addition of NSTAR ($54.2 million) and the consolidation of CYAPC and YAEC ($13.7 million).  Excluding the impact of NSTAR and the consolidation of CYAPC and YAEC, depreciation increased due primarily to higher utility plant balances resulting from completed construction projects placed into service.


Amortization of Regulatory Assets, Net increased in 2013, as compared to 2012, due primarily to the following:


(Millions of Dollars)

Increase/(Decrease)

The addition of NSTAR's operations

$

45.8 

Recovery of transition costs at NSTAR Electric

 

91.9 

Amortization related to CL&P's SBC and CTA

 

(6.8)

Other

 

(4.4)

 

$

126.5 


Amortization of Rate Reduction Bonds decreased in 2013, as compared to 2012, due primarily to the maturity of NSTAR Electric's, PSNH's, and WMECO's RRBs in 2013, partially offset by the addition of NSTAR Electric's amortization ($15.1 million).


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




48


Taxes Other Than Income Taxes increased in 2013, as compared to 2012, due primarily to the addition of NSTAR's operations ($37.8 million).  In addition, there was an increase in property taxes ($36.6 million) as a result of an increase in Property, Plant and Equipment and an increase in the property tax rates, and an increase in the Connecticut gross earnings tax ($9.1 million) attributable to an increase in gross earnings.


Interest Expense increased $8.8 million in 2013, as compared to 2012, due primarily to the addition of NSTAR's operations ($22 million) and lower interest income on deferred transition costs ($10.6 million), partially offset by a decrease in Other Interest due primarily to the favorable impact from the resolution of a state income tax audit in the first quarter of 2013, lower interest on short-term debt ($8.8 million) and lower interest on RRBs ($6.1 million).


Other Income, Net increased $10.2 million in 2013, as compared to 2012, due primarily to higher gains on the NU supplemental benefit trust ($6 million) and an increase related to officer insurance policies ($1.7 million).


Income Tax Expense

 

 

 

For the Years Ended December 31,

 

(Millions of Dollars)

2013

 

2012 (a)

 

Increase

 

Percent

 

Income Tax Expense

$

426.9

 

$

274.9

 

$

152.0

 

55.3

%


(a) The 2012 results include the operations of NSTAR beginning April 10, 2012.


Income Tax Expense increased in 2013, as compared to 2012, due primarily to higher pre-tax earnings ($81 million), the absence in 2013 of both prior year Connecticut and Massachusetts merger settlement agreement impacts ($41 million) and integration merger impacts ($23 million), along with various other items ($7 million).




49


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 years ended December 31, 2014, 2013, and 2012 included in this Annual Report on Form 10-K:


Comparison of 2014 to 2013:


 

 

 

For the Years Ended December 31,

 

 

 

 

 

 

 

 

 

 

Increase/

 

 

 

(Millions of Dollars)

2014 

2013 

(Decrease)

Percent

 

Operating Revenues

$

 2,692.6 

 

$

 2,442.3 

 

$

 250.3 

 

 10.2 

%

Operating Expenses:

 

 

 

 

 

 

 

 

 

 

 

 

Purchased Power and Transmission

 

 982.9 

 

 

 872.8 

 

 

 110.1 

 

 12.6 

 

 

Operations and Maintenance

 

 494.6 

 

 

 523.2 

 

 

 (28.6)

 

 (5.5)

 

 

Depreciation

 

 188.8 

 

 

 177.6 

 

 

 11.2 

 

 6.3 

 

 

Amortization of Regulatory Assets, Net

 

 59.3 

 

 

 4.9 

 

 

 54.4 

 

(a)

 

 

Energy Efficiency Programs

 

 156.3 

 

 

 89.8 

 

 

 66.5 

 

 74.1 

 

 

Taxes Other Than Income Taxes

 

 255.4 

 

 

 234.4 

 

 

 21.0 

 

 9.0 

 

 

 

Total Operating Expenses

 

 2,137.3 

 

 

 1,902.7 

 

 

 234.6 

 

 12.3 

 

Operating Income

 

 555.3 

 

 

 539.6 

 

 

 15.7 

 

 2.9 

 

Interest Expense

 

 147.4 

 

 

 133.6 

 

 

 13.8 

 

 10.3 

 

Other Income, Net

 

 13.4 

 

 

 15.1 

 

 

 (1.7)

 

 (11.3)

 

Income Before Income Tax Expense

 

 421.3 

 

 

 421.1 

 

 

 0.2 

 

 

Income Tax Expense

 

 133.5 

 

 

 141.7 

 

 

 (8.2)

 

 (5.8)

 

Net Income

$

 287.8 

 

$

 279.4 

 

$

 8.4 

 

 3.0 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(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 Years Ended December 31,

 

 

2014 

 

2013 

 

Decrease

 

Percent

 

Retail Sales Volumes in GWh

 

 22,046 

 

 

 22,404 

 

 

 (358)

 

 (1.6)

%


CL&P's Operating Revenues increased $250.3 million in 2014 compared to 2013.  The increase primarily reflects recovery of higher costs associated with the procurement of energy supply, which increased $275.4 million, and increased cost recovery related to our energy efficiency programs.  The energy supply costs were impacted by the overall wholesale electricity market in New England in which higher natural gas delivery costs had an adverse impact on the cost of electric energy purchased for our retail customers.  Energy supply costs are recovered from customers in rates through cost tracking mechanisms and therefore have no impact on earnings.  


Partially offsetting this increase was the impact of the $20.7 million net reserve recorded in 2014 as a result of the 2014 FERC ROE orders, as compared to the $12.8 million reserve recorded in 2013 for the FERC ALJ initial decision in the FERC base ROE complaints.  


Base distribution revenues increased $9.1 million in 2014 compared to 2013, which was primarily attributable to the impact of the December 1, 2014 base distribution rate increase and the impact of LBR, partially offset by the impact of cooler summer weather as well as energy efficiency programs.  Enhancements to CL&P's energy efficiency programs were mandated by the Connecticut legislature in 2013.  Through November 30, 2014, CL&P was permitted to bill customers for LBR related to reductions in sales volume as a result of energy efficiency and effective December 1, 2014, fluctuations in retail electric sales volumes do not impact earnings due to the PURA-approved revenue decoupling mechanism as a result of CL&P's base distribution rate case.  The revenue decoupling mechanism provides a base amount of distribution revenues ($1.041 billion on an annual basis) that effectively breaks the relationship between revenues and customer electricity usage.  The revenue decoupling mechanism is designed to allow CL&P to encourage energy efficiency for its customers without negatively impacting its revenues.  


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 in 2014, as compared to 2013, due primarily to the following:


(Millions of Dollars)

Increase/(Decrease)

Purchased Power Costs

$

169.7 

Transmission Costs

 

(50.8)

Other

 

(8.8)

Total Purchased Power and Transmission

$

110.1 


Included in purchased power are the costs associated with CL&P's generation services charge (GSC) and deferred energy supply 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 third party suppliers.  The increase in purchased power was due primarily to higher average supply prices and increased standard offer load as a result of customers returning 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 part of base distribution rates with changes impacting earnings (non-tracked costs).  Operations and Maintenance decreased in 2014, as compared to 2013, driven by a $38.4 million reduction in non-tracked costs, which was primarily attributable to lower labor and other employee-related costs, including pension costs, and lower storm restoration costs, partially offset



50


by an increase in costs for the implementation of a new outage restoration program that began in the second quarter of 2014.  Partially offsetting this decrease was a $9.8 million increase in tracked costs, which have no earnings impact, that was primarily attributable to higher tracked bad debt expense and increased transmission maintenance expenses.


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


Amortization of Regulatory Assets, Net¸ increased in 2014, as compared to 2013.  Fluctuations in energy supply and energy-related costs, which are the primary drivers in amortization, are recovered from customers in rates through cost tracking mechanisms and have no impact on earnings.  


Energy Efficiency Programs, which are tracked costs, increased in 2014, as compared to 2013, due primarily to expanded energy conservation programs in 2014 as a result of 2013 legislative action.  In 2013, Connecticut enacted into law Public Act 13-298, which implemented a number of recommendations, including allowing electric distribution companies to recover their costs as well as LBR from various state energy policy initiatives and expanded energy efficiency programs.


Taxes Other Than Income Taxes increased in 2014, as compared to 2013, due primarily to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates.


Interest Expense increased in 2014, as compared to 2013, due primarily to an increase in interest on long-term debt ($5 million) 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 2014 and the absence in 2014 of the favorable impact from the resolution of a state income tax audit in 2013.


Other Income, Net decreased in 2014, as compared to 2013, due primarily to lower unrealized gains on the assets supporting the deferred compensation plans ($6.7 million), partially offset by a gain on the sale of land ($4.5 million).


Income Tax Expense decreased in 2014, as compared to 2013, due primarily to lower state taxes, which includes the reduction in the valuation allowance for state tax positions, and various other impacts.


EARNINGS SUMMARY


CL&P's earnings increased in 2014, as compared to 2013, due primarily to a decrease in operations and maintenance costs primarily attributable to lower employee-related costs, as well as lower income tax expense due to the net reduction in the valuation allowance for state tax positions.  Partially offsetting these favorable earnings impacts were lower retail electric sales volumes, higher depreciation expense, higher property tax expense, higher interest expense and the after-tax reserve recorded for the 2014 FERC ROE orders as compared to the reserve recorded in 2013 for the FERC ALJ initial decision in the FERC base ROE complaints.


Comparison of 2013 to 2012:


 

 

 

Operating Revenues and Expenses

 

 

For the Years Ended December 31,

 

(Millions of Dollars)

2013 

 

2012 

 

Increase/

 

Percent

 

(Decrease)

 

Operating Revenues

$

 2,442.3 

 

$

 2,407.4 

 

$

 34.9 

 

 1.4 

%

Operating Expenses:

 

 

 

 

 

 

 

 

 

 

 

 

Purchased Power and Transmission

 

 872.8 

 

 

 858.2 

 

 

 14.6 

 

 1.7 

 

 

Operations and Maintenance

 

 523.2 

 

 

 635.7 

 

 

 (112.5)

 

 (17.7)

 

 

Depreciation

 

 177.6 

 

 

 166.9 

 

 

 10.7 

 

 6.4 

 

 

Amortization of Regulatory Assets, Net

 

 4.9 

 

 

 14.4 

 

 

 (9.5)

 

 (66.0)

 

 

Energy Efficiency Programs

 

 89.8 

 

 

 89.3 

 

 

 0.5 

 

 0.6 

 

 

Taxes Other Than Income Taxes

 

 234.4 

 

 

 215.9 

 

 

 18.5 

 

 8.6 

 

 

 

Total Operating Expenses

 

 1,902.7 

 

 

 1,980.4 

 

 

 (77.7)

 

 (3.9)

 

Operating Income

$

 539.6 

 

$

 427.0 

 

$

 112.6 

 

 26.4 

%


Operating Revenues

CL&P's retail sales were as follows:

 

 

For the Years Ended December 31,

 

 

 

2013 

 

2012 

 

Increase

 

Percent

 

Retail Sales in GWh

 22,404 

 

 22,109 

 

 295 

 

 1.3 

%


CL&P's Operating Revenues increased in 2013, as compared to 2012, due primarily to:


·

A $15.8 million increase in transmission revenues reflecting recovery of higher transmission expenses and continuing transmission infrastructure investments.  The increase was partially offset by the establishment of a reserve related to the FERC ALJ initial decision in the third quarter of 2013.


·

A $13.5 million increase in base distribution revenues reflecting a 1.3 percent increase in retail sales.  This increase was due primarily to the colder winter weather experienced in early and late 2013.


·

The remaining $5.6 million increase was due primarily to higher collections of costs through reconciling cost tracking mechanisms.  These revenues are fully reconciled to the related costs.  Therefore this increase in revenues had no impact on earnings.  



51



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


(Millions of Dollars)

Increase/(Decrease)

Transmission Costs

$

45.8 

Deferred Fuel Costs

 

28.7 

GSC Supply Costs

 

(44.2)

Purchased Power Contracts

 

(12.1)

CfD Costs

 

(7.3)

Other

 

3.7 

 

$

14.6 


The increase in transmission costs was the result of an increase in the retail transmission deferral, which related rates are adjusted on an annual basis as a result of collecting or refunding costs of the transmission systems to customers.  The decrease in GSC supply costs was due primarily to lower average supply prices.  On July 1, 2013, CL&P began to procure approximately thirty percent of GSC load.  Costs associated with the remaining seventy percent of the GSC load are the contractual amounts CL&P must pay to various suppliers that have been awarded the right to supply SS and LRS load through a competitive solicitation process.  Purchased Power and Transmission costs are included in regulatory-approved tracking mechanisms and do not impact earnings.


Operations and Maintenance decreased in 2013, as compared to 2012, due primarily to the absence in 2013 of costs recognized in the second quarter of 2012 as a result of the Connecticut merger settlement agreement (which established a $40 million storm fund reserve and provided a $25 million bill credit to customers).  In addition, there were lower distribution operating costs ($10.2 million), the absence in 2013 of amortization of the PBOP transition obligation ($6.1 million), lower distribution general and administrative costs ($7.5 million) and lower distribution costs related to customer Energy Independence Act incentives ($6.3 million).  These lower costs were partially offset by an increase in distribution routine maintenance and storm-related costs ($7.4 million).


Depreciation increased in 2013, as compared to 2012, due primarily to higher utility plant balances resulting from completed construction projects placed into service.


Amortization of Regulatory Assets, Net decreased in 2013, as compared to 2012, due primarily to a lower net SBC deferral, partially offset by a higher net CTA deferral.  SBC revenues were $23 million lower in 2013, as compared to 2012, partially offset by higher hardship program costs of $6.6 million in 2013.  CTA revenues were $13.9 million higher in 2013, as compared to 2012, and costs were $30.5 million lower in 2013, as compared to 2012.  DOE refunds of $21.6 million were returned to customers in the second half of 2013.  All of these items represent reconciliations of previously incurred costs and have a corresponding revenue offset, so there is no earnings impact.  


Taxes Other Than Income Taxes increased in 2013, as compared to 2012, due primarily to an increase in property taxes as a result of an increase in Property, Plant and Equipment and an increase in the property tax rates ($11.5 million).  In addition, there was an increase in the Connecticut gross earnings tax attributable to an increase in gross earnings ($7.6 million).


Interest Expense increased $0.5 million in 2013, as compared to 2012, due primarily to higher interest on long-term debt ($5.7 million), partially offset by a decrease in other interest as a result of a favorable impact from the resolution of a state income tax audit in the first quarter of 2013 ($5.4 million).


Other Income increased $4.8 million in 2013, as compared to 2012, due primarily to higher gains on the NU supplemental benefit trust.


Income Tax Expense

 

For the Years Ended December 31,

 

(Millions of Dollars)

2013

 

2012

 

Increase

 

Percent

 

Income Tax Expense

$

141.7

 

$

94.4

 

$

47.3

 

50.1

%


Income Tax Expense increased in 2013, as compared to 2012, due primarily to higher pre-tax earnings ($17.1 million), the absence in 2013 of the impact of costs recognized as a result of the Connecticut merger settlement agreement ($26.6 million), and higher state taxes ($5.7 million), partially offset by various other items ($2.1 million).  


LIQUIDITY


In 2014, CL&P had cash flows provided by operating activities of $612.4 million, compared with $495.3 million in 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, and the favorable cash flow impact resulting from an increase in recoveries from customers in 2014, as compared to 2013, relating to regulatory cost recovery tracking mechanisms, partially offset by higher income tax payments in 2014, as compared to 2013, and changes in working capital items.  


In 2013, CL&P had cash flows provided by operating activities of $495.3 million, compared with $211.9 million in 2012.  The improved cash flows were due primarily to a decrease of approximately $75 million in cash disbursements for storm restoration costs associated primarily with Tropical Storm Irene and the October 2011 snowstorm, the absence of approximately $27 million in 2012 CL&P customer bill credits associated with the October 2011 snowstorm and the absence of $25 million in 2012 CL&P customer bill credits associated with the Connecticut settlement agreement.  In addition, operating cash flows benefited from an increase in regulatory overrecoveries where such revenues exceeded costs resulting in a favorable cash flow impact, higher net income and timing of payables.  Partially offsetting improved cash flows were income tax payments of $55 million in 2013, compared with income tax refunds of $42 million in 2012.



52



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.  CL&P's investments totaled $515.7 million in 2014, compared with $434.9 million in 2013.


Effective July 23, 2014, NU parent and certain of its subsidiaries, including CL&P, extended the expiration date of their joint $1.45 billion revolving credit facility for one additional year to September 6, 2019.  The revolving credit facility is to be used primarily to backstop NU parent's $1.45 billion commercial paper program.  The commercial paper program allows NU parent to issue commercial paper as a form of short-term debt with intercompany loans to certain subsidiaries, including CL&P.  As of December 31, 2014 and 2013, there were intercompany loans from NU parent of $133.4 million and $287.3 million, respectively, to CL&P.


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 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 2014 included $171.2 million in common stock dividends paid to NU parent.




53


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 years ended December 31, 2014 and 2013 included in this Annual Report on Form 10-K:  


 

 

 

For the Years Ended December 31,

 

 

 

 

 

 

 

 

 

 

Increase/

 

 

 

(Millions of Dollars)

2014 

2013 

(Decrease)

Percent

 

Operating Revenues

$

 2,536.7 

 

$

 2,493.5 

 

$

 43.2 

 

 1.7 

%

Operating Expenses:

 

 

 

 

 

 

 

 

 

 

 

 

Purchased Power and Transmission

 

 1,122.3 

 

 

 849.1 

 

 

 273.2 

 

 32.2 

 

 

Operations and Maintenance

 

 327.0 

 

 

 376.4 

 

 

 (49.4)

 

 (13.1)

 

 

Depreciation

 

 188.7 

 

 

 180.3 

 

 

 8.4 

 

 4.7 

 

 

Amortization of Regulatory Assets/(Liabilities), Net

 

 (6.3)

 

 

 230.1 

 

 

 (236.4)

 

(a)

 

 

Amortization of Rate Reduction Bonds

 

 - 

 

 

 15.1 

 

 

 (15.1)

 

 (100.0)

 

 

Energy Efficiency Programs

 

 193.5 

 

 

 206.5 

 

 

 (13.0)

 

 (6.3)

 

 

Taxes Other Than Income Taxes

 

 133.0 

 

 

 127.8 

 

 

 5.2 

 

 4.1 

 

 

 

Total Operating Expenses

 

 1,958.2 

 

 

 1,985.3 

 

 

 (27.1)

 

 (1.4)

 

Operating Income

 

 578.5 

 

 

 508.2 

 

 

 70.3 

 

 13.8 

 

Interest Expense

 

 77.9 

 

 

 70.4 

 

 

 7.5 

 

 10.7 

 

Other Income, Net

 

 4.5 

 

 

 3.6 

 

 

 0.9 

 

 25.0 

 

Income Before Income Tax Expense

 

 505.1 

 

 

 441.4 

 

 

 63.7 

 

 14.4 

 

Income Tax Expense

 

 202.0 

 

 

 172.9 

 

 

 29.1 

 

 16.8 

 

Net Income

$

 303.1 

 

$

 268.5 

 

$

 34.6 

 

 12.9 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

 

 

 

 

 

 

 

 

 

 

 

NSTAR Electric's retail sales volumes were as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Years Ended December 31,

 

 

2014 

 

2013 

 

Decrease

 

Percent

 

Retail Sales Volumes in GWh

 

 20,925 

 

 

 21,306 

 

 

 (381)

 

 (1.8)

%


NSTAR Electric's Operating Revenues increased $43.2 million in 2014 compared to 2013.  The increase primarily reflects recovery of higher costs associated with the procurement of energy supply, which increased $195.5 million.  The energy supply costs were impacted by the overall wholesale electricity market in New England in which higher natural gas delivery costs had an adverse impact on the cost of electric energy purchased for our retail customers.  Energy supply costs are recovered from customers in rates through cost tracking mechanisms and therefore have no impact on earnings.  These costs and related recovery impacts were partially offset by decreases in transition cost recovery revenues, which are recovered through cost tracking mechanisms, reflecting the full collection in 2013 of previously deferred costs, as well as the full amortization of RRBs.  


Base distribution revenues decreased in 2014, as compared to 2013, due primarily to cooler summer weather and an increase in customer conservation efforts due to the impact of energy efficiency programs.  NSTAR Electric recovers LBR related to reductions in sales volume as a result of energy efficiency.  In 2014, including the impact from the recognition of LBR, base distribution revenues increased in 2014, compared to 2013, by $3.7 million.  


Transmission revenues increased $21.7 million in 2014, as compared to 2013, due primarily to the recovery of higher revenue requirements associated with ongoing investments in our transmission infrastructure.  This increase was partially offset by the impact of the $7.9 million net reserve recorded in 2014 as a result of the 2014 FERC ROE orders, compared to the $5.7 million reserve recorded in 2013 for the FERC ALJ initial decision in the FERC base ROE complaints.  


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 in 2014, as compared to 2013, due primarily to the following:  


(Millions of Dollars)

Increase

Purchased Power Costs

$

202.9 

Transmission Costs

 

64.6 

Other

 

5.7 

Total Purchased Power and Transmission

$

273.2 


Included in purchased power are the costs associated with NSTAR Electric's basic service charge and deferred energy supply costs.  The basic service charge recovers energy-related costs incurred as a result of providing electric generation service supply to all customers that have not migrated to third party suppliers.  The increase in purchased power was due primarily to higher average energy supply prices.  The increase in transmission costs was due primarily to higher regional transmission expense.  


Operations and Maintenance expense includes tracked costs and costs that are part of base distribution rates with changes impacting earnings (non-tracked costs).  Operations and Maintenance decreased in 2014, as compared to 2013, driven by a $57.4 million reduction in non-tracked costs, which was primarily attributable to lower labor and other employee-related costs and lower storm restoration costs.  Partially offsetting this decrease was an $8 million increase in tracked costs, which have no earnings impact, that was primarily attributable to an increased level of recovery of deferred storm costs and increased transmission maintenance expenses.




54


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


Amortization of Regulatory Assets/(Liabilities), Net, decreased due primarily to the absence in 2014 of the recovery of tracked transition costs, reflecting the full collection in 2013 of these previously deferred costs.  Fluctuations in these costs are recovered from customers in rates through cost tracking mechanisms and have no impact on earnings.  


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


Energy Efficiency Programs, which are tracked costs, decreased in 2014, as compared to 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 in 2014, as compared to 2013, due primarily to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates.


Interest Expense increased in 2014, as compared to 2013, due primarily to lower interest income from a decrease in the recovery of previously deferred tracked transition costs ($9.9 million), partially offset by a decrease in interest on long-term debt ($2 million).


Income Tax Expense increased in 2014, as compared to 2013, due primarily to higher pre-tax earnings ($22.4 million), and higher state taxes ($6.7 million).


EARNINGS SUMMARY


NSTAR Electric's earnings increased in 2014, as compared to 2013, due primarily to lower operations and maintenance costs primarily attributable to lower employee-related costs and higher transmission earnings, partially offset by higher interest expense, higher depreciation expense, higher property tax expense and the after-tax reserve recorded for the 2014 FERC ROE orders as compared to the reserve recorded in 2013 for the FERC ALJ initial decision in the FERC base ROE complaints.


LIQUIDITY


NSTAR Electric had cash flows provided by operating activities of $533 million in 2014, compared with $510.4 million in 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, and $30.2 million in DOE damages proceeds in 2014 from the Yankee Companies associated with the spent nuclear fuel litigation.  These favorable cash flow impacts were partially offset by a $38.3 million increase in Pension and PBOP Plan cash contributions in 2014 compared to 2013, the unfavorable cash flow impact resulting from the absence in 2014 of the recovery of previously deferred tracked transition costs that were fully collected in 2013, the absence of costs recovered in rates related to the RRBs that were fully amortized in 2013, and an increase in income taxes paid.


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




55


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 years ended December 31, 2014 and 2013 included in this Annual Report on Form 10-K:


 

 

 

For the Years Ended December 31,

 

 

 

 

 

 

 

 

 

 

Increase/

 

 

 

(Millions of Dollars)

2014 

2013 

(Decrease)

Percent

 

Operating Revenues

$

 959.5 

 

$

 935.4 

 

$

 24.1 

 

 2.6 

%

Operating Expenses:

 

 

 

 

 

 

 

 

 

 

 

 

Purchased Power, Fuel and Transmission

 

 313.7 

 

 

 269.8 

 

 

 43.9 

 

 16.3 

 

 

Operations and Maintenance

 

 261.9 

 

 

 267.8 

 

 

 (5.9)

 

 (2.2)

 

 

Depreciation

 

 98.4 

 

 

 91.6 

 

 

 6.8 

 

 7.4 

 

 

Amortization of Regulatory Liabilities, Net

 

 (29.6)

 

 

 (20.4)

 

 

 (9.2)

 

 45.1 

 

 

Amortization of Rate Reduction Bonds

 

 - 

 

 

 19.7 

 

 

 (19.7)

 

 (100.0)

 

 

Energy Efficiency Programs

 

 14.3 

 

 

 14.5 

 

 

 (0.2)

 

 (1.4)

 

 

Taxes Other Than Income Taxes

 

 71.4 

 

 

 67.2 

 

 

 4.2 

 

 6.3 

 

 

 

Total Operating Expenses

 

 730.1 

 

 

 710.2 

 

 

 19.9 

 

 2.8 

 

Operating Income

 

 229.4 

 

 

 225.2 

 

 

 4.2 

 

 1.9 

 

Interest Expense

 

 45.4 

 

 

 46.2 

 

 

 (0.8)

 

 (1.7)

 

Other Income, Net

 

 2.0 

 

 

 3.5 

 

 

 (1.5)

 

 (42.9)

 

Income Before Income Tax Expense

 

 186.0 

 

 

 182.5 

 

 

 3.5 

 

 1.9 

 

Income Tax Expense

 

 72.1 

 

 

 71.1 

 

 

 1.0 

 

 1.4 

 

Net Income

$

 113.9 

 

$

 111.4 

 

$

 2.5 

 

 2.2 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

 

 

 

 

 

 

 

 

 

 

 

PSNH's retail sales volumes were as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Years Ended December 31,

 

 

2014 

 

2013 

 

Decrease

 

Percent

 

Retail Sales Volumes in GWh

 

 7,886 

 

 

 7,938 

 

 

 (52)

 

 (0.7)

%


PSNH's Operating Revenues increased $24.1 million in 2014 compared to 2013.  The increase primarily reflects the recovery of higher costs associated with the procurement of energy supply and the generation of electricity for our customers, which increased $19.8 million.  The energy supply costs were impacted by higher natural gas delivery costs, which had an adverse impact on the cost of electric energy purchased for our retail customers.  Also reflected in the revenue increase were increases of $6.3 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.  These increases were partially offset by a decrease in stranded cost recovery revenues, which are recovered through cost tracking mechanisms, due to the refund to customers of DOE damages proceeds received from the Yankee Companies resulting from the spent nuclear fuel litigation.  


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 in 2014, as compared to 2013, due primarily to the following:


(Millions of Dollars)

Increase/(Decrease)

Generation Fuel Costs

$

41.6

Transmission Costs

 

13.2

Purchased Power Costs

 

(9.4)

Other

 

(1.5)

Total Purchased Power, Fuel and Transmission

$

43.9


The increase in generation fuel costs was due primarily to an increase in the amount of electricity generated by PSNH facilities in 2014, as compared to 2013.  Included in purchased power are the costs associated with the PSNH energy service charge.  The decrease in purchased power costs was a result of purchasing less power from third party suppliers due to increased PSNH generation.  The increase in transmission costs was the 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 part of base distribution rates with changes impacting earnings (non-tracked costs).  Operations and Maintenance decreased in 2014, as compared to 2013, driven by an $8.3 million reduction in non-tracked costs, which was primarily attributable to lower labor and other employee-related costs, including pension costs, and lower storm restoration costs.  Partially offsetting this decrease was a $2.4 million increase in tracked costs, which have no earnings impact, that was primarily attributable to increased maintenance activities at PSNH's generating facilities.


Depreciation increased in 2014, as compared to 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 the default energy service charge and other amortizations in 2014, as compared to 2013.  Fluctuations in these costs are recovered from customers in rates through cost tracking mechanisms and have no impact on earnings.  




56


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


Taxes Other Than Income Taxes increased in 2014, as compared to 2013, due primarily to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates.


Other Income, Net decreased in 2014, as compared to 2013, due primarily to lower unrealized gains on the assets supporting the deferred compensation plans ($1.8 million).


Income Tax Expense increased in 2014, as compared to 2013, due primarily to higher pre-tax earnings.


EARNINGS SUMMARY


PSNH's earnings increased in 2014, as compared to 2013, due primarily to higher transmission earnings, a decrease in operations and maintenance costs primarily attributable to lower employee-related costs, and 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 was higher depreciation expense.


LIQUIDITY


PSNH had cash flows provided by operating activities of $248 million in 2014, compared with $188.1 million in 2013.  The improved operating cash flows were due primarily to the absence of $108.3 million in Pension Plan cash contributions made in 2013, $14.5 million in DOE damages proceeds received in 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, and the favorable impact of the NHPUC-approved distribution rate increases that were effective July 1, 2013.  These favorable cash flow impacts were partially offset by higher income tax payments in 2014, as compared to 2013, and the absence of costs recovered in rates related to the RRBs that were fully amortized in 2013.  




57


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 years ended December 31, 2014 and 2013 included in this Annual Report on Form 10-K:


 

 

 

For the Years Ended December 31,

 

 

 

 

 

 

 

 

 

 

Increase/

 

 

 

(Millions of Dollars)

2014 

2013 

(Decrease)

Percent

 

Operating Revenues

$

 493.4 

 

$

 472.7 

 

$

 20.7 

 

 4.4 

%

Operating Expenses:

 

 

 

 

 

 

 

 

 

 

 

 

Purchased Power and Transmission

 

 172.9 

 

 

 147.1 

 

 

 25.8 

 

 17.5 

 

 

Operations and Maintenance

 

 89.4 

 

 

 96.2 

 

 

 (6.8)

 

 (7.1)

 

 

Depreciation

 

 41.9 

 

 

 37.6 

 

 

 4.3 

 

 11.4 

 

 

Amortization of Regulatory Assets/(Liabilities), Net

 

 (6.2)

 

 

 (3.2)

 

 

 (3.0)

 

 93.8 

 

 

Amortization of Rate Reduction Bonds

 

 - 

 

 

 7.8 

 

 

 (7.8)

 

 (100.0)

 

 

Energy Efficiency Programs

 

 42.9 

 

 

 39.5 

 

 

 3.4 

 

 8.6 

 

 

Taxes Other Than Income Taxes

 

 34.9 

 

 

 28.4 

 

 

 6.5 

 

 22.9 

 

 

 

Total Operating Expenses

 

 375.8 

 

 

 353.4 

 

 

 22.4 

 

 6.3 

 

Operating Income

 

 117.6 

 

 

 119.3 

 

 

 (1.7)

 

 (1.4)

 

Interest Expense

 

 24.9 

 

 

 24.8 

 

 

 0.1 

 

 0.4 

 

Other Income, Net

 

 2.4 

 

 

 3.3 

 

 

 (0.9)

 

 (27.3)

 

Income Before Income Tax Expense

 

 95.1 

 

 

 97.8 

 

 

 (2.7)

 

 (2.8)

 

Income Tax Expense

 

 37.3 

 

 

 37.4 

 

 

 (0.1)

 

 (0.3)

 

Net Income

$

 57.8 

 

$

 60.4 

 

$

 (2.6)

 

 (4.3)

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

 

 

 

 

 

 

 

 

 

 

 

WMECO's retail sales volumes were as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Years Ended December 31,

 

 

2014 

 

2013 

 

Decrease

 

Percent

 

Retail Sales Volumes in GWh

 

 3,586 

 

 

 3,683 

 

 

 (97)

 

 (2.6)

%


WMECO's Operating Revenues increased $20.7 million in 2014 compared to 2013.  The increase primarily reflects recovery of higher costs associated with the procurement of energy supply, which increased $15.2 million.  The energy supply costs were impacted by the overall wholesale electricity market in New England in which higher natural gas delivery costs had an adverse impact on the cost of electric energy purchased for our retail customers.  Energy supply costs are recovered from customers in rates through cost tracking mechanisms and therefore have no impact on earnings.


Transition cost recovery revenues, which are recovered through cost tracking mechanisms, decreased due to the refund to customers of DOE damages 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.


Transmission revenues increased in 2014 compared to 2013 due primarily to the recovery of higher revenue requirements associated with ongoing investments in our transmission infrastructure.  There was also a $3.9 million increase in revenues that impacts earnings due to the reversal in 2014 of a previously established wholesale billing adjustment.  Partially offsetting the increase was the impact of the $5.6 million net reserve recorded in 2014 as a result of the 2014 FERC ROE orders, as compared to the $2.9 million reserve recorded in 2013 for the FERC ALJ initial decision in the FERC base ROE complaints.  


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 in 2014, as compared to 2013, due primarily to the following:


(Millions of Dollars)

Increase/(Decrease)

Purchased Power Costs

$

16.6

Transmission Costs

 

11.6

Other

 

(2.4)

Total Purchased Power and Transmission

$

25.8


Included in purchased power are the costs associated with WMECO's basic service charge and deferred energy supply costs.  The basic service charge recovers energy-related costs incurred as a result of providing electric generation service supply to all customers that have not migrated to third party suppliers.  The increase in purchased power was due primarily to higher average supply prices and increased load as a result of customers returning to basic service from third party suppliers.  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 part of base distribution rates with changes impacting earnings (non-tracked costs).  Operations and Maintenance decreased in 2014, as compared to 2013, driven by a $4.8 million reduction in non-tracked costs, which was primarily attributable to lower labor and other employee-related costs, and a $2 million reduction in tracked costs, which have no earnings impact, that was primarily attributable to lower labor and other employee-related costs, including pension costs.




58


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


Amortization of Regulatory Assets/(Liabilities), Net¸ reflects a decrease in the recovery of transition costs primarily due to the refund of the DOE damages proceeds to customers in 2014, as compared to 2013.  Fluctuations in these costs are recovered from or refunded to customers in rates through cost tracking mechanisms and have no impact on earnings.   


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


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


Taxes Other Than Income Taxes increased in 2014, as compared to 2013, due primarily to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates.


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


Income Tax Expense decreased in 2014, as compared to 2013, due primarily to lower pre-tax earnings.


EARNINGS SUMMARY


WMECO's earnings decreased in 2014, as compared to 2013, due primarily to the after-tax reserve recorded for the 2014 FERC ROE orders as compared to the reserve recorded in 2013 for the FERC ALJ initial decision in the FERC base ROE complaints, higher depreciation expense and higher property tax expense.  Partially offsetting these unfavorable earnings impacts were a decrease in operations and maintenance expense primarily attributable to lower employee-related costs, and the reversal of a previously established wholesale billing adjustment.  


LIQUIDITY


WMECO had cash flows provided by operating activities of $153.3 million in 2014, compared with $178.8 million in 2013.  The decrease in operating cash flows was due primarily to higher income tax payments in 2014, as compared to 2013, and the absence of costs recovered in rates related to the RRBs that were fully amortized in 2013, partially offset by the favorable impact of changes in working capital and $18.9 million in DOE damages proceeds received in 2014 from the Yankee Companies associated with the spent nuclear fuel litigation.  




59


Item 7A.

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


We have an Enterprise Risk Management (ERM) program for identifying the principal risks of the Company.  Our ERM program involves the application of a well-defined, enterprise-wide methodology designed to allow our Risk Committee, comprised of our senior officers and directors of the Company, to identify, categorize, prioritize, and mitigate the principal risks to the Company.  The ERM program is integrated with other assurance functions throughout the Company including Compliance, Auditing, and Insurance to ensure appropriate coverage of risks that could impact the Company.  In addition to known risks, ERM identifies emerging risks to the Company, through participation in industry groups, discussions with management and in consultation with outside advisers.  Our management then analyzes risks to determine materiality, likelihood, impact and develops mitigation strategies.  Management broadly considers our business model, the utility industry, the global economy and the current environment to identify risks.  The findings of this process are periodically discussed with the Finance Committee of our Board of Trustees, as well as with other Board Committees or the full Board of Trustees, as appropriate, including reporting on how these issues are being measured and managed.  The Finance Committee is responsible for oversight of the Company's ERM program and enterprise-wide risks as well as specific risks associated with insurance, credit, financing, investments, pensions and overall system security including cyber security.  However, there can be no assurances that the Enterprise Risk Management process will identify or manage every risk or event that could impact our financial position, results of operations or cash flows.


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.  As of December 31, 2014, approximately 91 percent of our long-term debt, including fees and interest due for spent nuclear fuel disposal costs, was at a fixed interest rate.  The remaining long-term debt is at variable interest rates and is subject to interest rate risk that could result in earnings volatility.  Assuming a one percentage point increase in our variable interest rates, annual interest expense would have increased by a pre-tax amount of $7.7 million.  


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


Our Regulated companies are subject to credit risk from certain long-term or high-volume supply contracts with energy marketing companies.  Our Regulated companies manage the credit risk with these counterparties in accordance with established credit risk practices and monitor contracting risks, including credit risk.  As of December 31, 2014, our Regulated companies held collateral from counterparties related to our standard service contracts.  As of December 31, 2014, NU had cash posted with ISO-NE related to energy purchase transactions.


For further information on cash collateral deposited and posted with counterparties, see Note 1G, "Summary of Significant Accounting Policies - Restricted Cash and Other Deposits," and Note 4, "Derivative Instruments," to the financial statements.


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.  



























































































60



Item 8.

Financial Statements and Supplementary Data

 

 

 

NU

 

 

 

Company Report on Internal Controls Over Financial Reporting

 

 

Report of Independent Registered Public Accounting Firm

 

 

Consolidated Financial Statements

 

 

 

 

CL&P

 

 

 

Company Report on Internal Controls Over Financial Reporting

 

 

Report of Independent Registered Public Accounting Firm

 

 

Financial Statements

 

 

 

 

NSTAR Electric

 

 

 

Company Report on Internal Controls Over Financial Reporting

 

 

Report of Independent Registered Public Accounting Firm

 

 

Consolidated Financial Statements

 

 

 

 

PSNH

 

 

 

Company Report on Internal Controls Over Financial Reporting

 

 

Report of Independent Registered Public Accounting Firm

 

 

Consolidated Financial Statements

 

 

 

 

WMECO

 

 

 

Company Report on Internal Controls Over Financial Reporting

 

 

Report of Independent Registered Public Accounting Firm

 

 

Financial Statements

 




61


Company Report on Internal Controls Over Financial Reporting


Northeast Utilities


Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of Northeast Utilities and subsidiaries (NU or the Company) and of other sections of this annual report.  NU's internal controls over financial reporting were audited by Deloitte & Touche LLP.


Management is responsible for establishing and maintaining adequate internal controls over financial reporting.  The Company's internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.  There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business.  Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment.  


Under the supervision and with the participation of the principal executive officer and principal financial officer, NU conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting were effective as of December 31, 2014.



February 25, 2015




62


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Trustees and Shareholders of Northeast Utilities:


We have audited the accompanying consolidated balance sheets of Northeast Utilities and subsidiaries (the "Company") as of December 31, 2014 and 2013, and the related consolidated statements of income, comprehensive income, common shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2014.  Our audits also included the financial statement schedules listed in the Index at Item 15 of Part IV.  We also have audited the Company's internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.  The Company's management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Company Report on Internal Controls Over Financial Reporting.  Our responsibility is to express an opinion on these financial statements and financial statement schedules and an opinion on the Company's internal control over financial reporting based on our audits.


We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects.  Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.  Our audits also included performing such other procedures as we considered necessary in the circumstances.  We believe that our audits provide a reasonable basis for our opinions.


A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.


Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis.  Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.


In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Northeast Utilities and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.  Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.  Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.


/s/ Deloitte & Touche LLP


Hartford, Connecticut

February 25, 2015




63



NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

 

 

 

 

 

 

 

 

 

 

As of December 31,

(Thousands of Dollars)

2014 

 

2013 

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

 

Current Assets:

 

 

 

 

 

 

Cash and Cash Equivalents

$

 38,703 

 

$

 43,364 

 

Receivables, Net

 

 856,346 

 

 

 765,391 

 

Unbilled Revenues

 

 211,758 

 

 

 224,982 

 

Taxes Receivable

 

 337,307 

 

 

 16,629 

 

Fuel, Materials and Supplies

 

 349,664 

 

 

 303,233 

 

Regulatory Assets

 

 672,493 

 

 

 535,791 

 

Prepayments and Other Current Assets

 

 226,194 

 

 

 197,659 

Total Current Assets

 

 2,692,465 

 

 

 2,087,049 

 

 

 

 

 

 

 

Property, Plant and Equipment, Net

 

 18,647,041 

 

 

 17,576,186 

 

 

 

 

 

 

 

Deferred Debits and Other Assets:

 

 

 

 

 

 

Regulatory Assets

 

 4,054,086 

 

 

 3,758,694 

 

Goodwill

 

 3,519,401 

 

 

 3,519,401 

 

Marketable Securities

 

 515,025 

 

 

 488,515 

 

Other Long-Term Assets

 

 349,957 

 

 

 365,692 

Total Deferred Debits and Other Assets

 

 8,438,469 

 

 

 8,132,302 

 

 

 

 

 

 

 

Total Assets

$

 29,777,975 

 

$

 27,795,537 


LIABILITIES AND CAPITALIZATION

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities:

 

 

 

 

 

   Notes Payable

$

 956,825 

 

$

 1,093,000 

   Long-Term Debt - Current Portion

 

 245,583 

 

 

 533,346 

   Accounts Payable

 

 868,231 

 

 

 742,251 

   Regulatory Liabilities

 

 235,022 

 

 

 204,278 

   Other Current Liabilities

 

 828,720 

 

 

 702,776 

Total Current Liabilities

 

 3,134,381 

 

 

 3,275,651 

 

 

 

 

 

 

 

 

Deferred Credits and Other Liabilities:

 

 

 

 

 

   Accumulated Deferred Income Taxes

 

 4,467,473 

 

 

 4,029,026 

   Regulatory Liabilities

 

 515,144 

 

 

 502,984 

   Derivative Liabilities

 

 409,632 

 

 

 624,050 

   Accrued Pension, SERP and PBOP

 

 1,638,558 

 

 

 896,844 

   Other Long-Term Liabilities

 

 874,387 

 

 

 923,053 

Total Deferred Credits and Other Liabilities

 

 7,905,194 

 

 

 6,975,957 

 

 

 

 

 

 

 

 

Capitalization:

 

 

 

 

 

   Long-Term Debt

 

 8,606,017 

 

 

 7,776,833 

 

 

 

 

 

 

 

 

   Noncontrolling Interest - Preferred Stock of Subsidiaries

 

 155,568 

 

 

 155,568 

 

 

 

 

 

 

 

 

   Equity:

 

 

 

 

 

 

Common Shareholders' Equity:

 

 

 

 

 

 

  Common Shares

 

 1,666,796 

 

 

 1,665,351 

 

  Capital Surplus, Paid In

 

 6,235,834 

 

 

 6,192,765 

 

  Retained Earnings

 

 2,448,661 

 

 

 2,125,980 

 

  Accumulated Other Comprehensive Loss

 

 (74,009)

 

 

 (46,031)

 

  Treasury Stock

 

 (300,467)

 

 

 (326,537)

     Common Shareholders' Equity

 

 9,976,815 

 

 

 9,611,528 

Total Capitalization

 

 18,738,400 

 

 

 17,543,929 

 

 

 

 

 

 

 

 

Commitments and Contingencies (Note 11)

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Liabilities and Capitalization

$

 29,777,975 

 

$

 27,795,537 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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



























































































64



NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Years Ended December 31,

(Thousands of Dollars, Except Share Information)

2014 

 

2013 

 

2012 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

$

 7,741,856 

 

$

 7,301,204 

 

$

 6,273,787 

 

 

 

 

 

 

 

 

 

 

 

Operating Expenses:

 

 

 

 

 

 

 

 

 

Purchased Power, Fuel and Transmission

 

 3,021,550 

 

 

 2,482,954 

 

 

 2,084,364 

 

Operations and Maintenance

 

 1,427,589 

 

 

 1,514,986 

 

 

 1,583,070 

 

Depreciation

 

 614,657 

 

 

 610,777 

 

 

 519,010 

 

Amortization of Regulatory Assets, Net

 

 10,704 

 

 

 206,322 

 

 

 79,762 

 

Amortization of Rate Reduction Bonds

 

 - 

 

 

 42,581 

 

 

 142,019 

 

Energy Efficiency Programs

 

 473,127 

 

 

 401,919 

 

 

 313,149 

 

Taxes Other Than Income Taxes

 

 561,380 

 

 

 512,230 

 

 

 434,207 

 

 

Total Operating Expenses

 

 6,109,007 

 

 

 5,771,769 

 

 

 5,155,581 

Operating Income

 

 1,632,849 

 

 

 1,529,435 

 

 

 1,118,206 

 

 

 

 

 

 

 

 

 

 

 

Interest Expense:

 

 

 

 

 

 

 

 

 

Interest on Long-Term Debt

 

 345,001 

 

 

 340,970 

 

 

 316,987 

 

Interest on Rate Reduction Bonds

 

 - 

 

 

 422 

 

 

 6,168 

 

Other Interest

 

 17,105 

 

 

 (2,693)

 

 

 6,790 

 

 

Interest Expense

 

 362,106 

 

 

 338,699 

 

 

 329,945 

Other Income, Net

 

 24,619 

 

 

 29,894 

 

 

 19,742 

Income Before Income Tax Expense

 

 1,295,362 

 

 

 1,220,630 

 

 

 808,003 

Income Tax Expense

 

 468,297 

 

 

 426,941 

 

 

 274,926 

Net Income

 

 827,065 

 

 

 793,689 

 

 

 533,077 

Net Income Attributable to Noncontrolling Interests

 

 7,519 

 

 

 7,682 

 

 

 7,132 

Net Income Attributable to Controlling Interest

$

 819,546 

 

$

 786,007 

 

$

 525,945 

 

 

 

 

 

 

 

 

 

 

 

Basic Earnings Per Common Share

$

 2.59 

 

$

 2.49 

 

$

 1.90 

 

 

 

 

 

 

 

 

 

 

 

Diluted Earnings Per Common Share

$

 2.58 

 

$

 2.49 

 

$

 1.89 

 

 

 

 

 

 

 

 

 

 

 

Weighted Average Common Shares Outstanding:

 

 

 

 

 

 

 

 

 

Basic

 

 316,136,748 

 

 

 315,311,387 

 

 

 277,209,819 

 

Diluted

 

 317,417,414 

 

 

 316,211,160 

 

 

 277,993,631 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 

 

 

 

 

 

 

 

 

 

 

Net Income

$

 827,065 

 

$

 793,689 

 

$

 533,077 

Other Comprehensive Income/(Loss), Net of Tax:

 

 

 

 

 

 

 

 

 

Qualified Cash Flow Hedging Instruments

 

 2,037 

 

 

 2,049 

 

 

 1,971 

 

Changes in Unrealized Gains/(Losses) on Other Securities

 

 315 

 

 

 (940)

 

 

 217 

 

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

 

 (30,330)

 

 

 25,714 

 

 

 (4,356)

Other Comprehensive Income/(Loss), Net of Tax

 

 (27,978)

 

 

 26,823 

 

 

 (2,168)

Comprehensive Income Attributable to Noncontrolling Interests

 

 (7,519)

 

 

 (7,682)

 

 

 (7,132)

Comprehensive Income Attributable to Controlling Interest

$

 791,568 

 

$

 812,830 

 

$

 523,777 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 



























































































65



NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accumulated

 

Total

 

 

 

 

 

Capital

 

Other

 

Common

 

 

 

Common Shares

Surplus,

Retained

Comprehensive

Treasury

Shareholders'

(Thousands of Dollars, Except Share Information)

Shares

Amount

Paid In

Earnings

Income/(Loss)

Stock

Equity

Balance as of January 1, 2012

177,158,692 

$ 980,264 

$ 1,797,884 

$ 1,651,875 

$ (70,686)

$ (346,667)

$ 4,012,670 

 

Net Income

 

 

 

533,077 

 

 

533,077 

 

Shares Issued in Connection with NSTAR Merger

136,048,595 

680,243 

4,358,027 

 

 

 

5,038,270 

 

Other Equity Impacts of Merger with NSTAR

 

 

2,938 

421 

 

 

3,359 

 

Dividends on Common Shares - $1.32 Per Share

 

 

 

(375,527)

 

 

(375,527)

 

Dividends on Preferred Stock

 

 

 

(7,029)

 

 

(7,029)

 

Issuance of Common Shares, $5 Par Value

408,018 

2,040 

11,287 

 

 

 

13,327 

 

Long-Term Incentive Plan Activity

 

 

(3,897)

 

 

 

(3,897)

 

Issuance of Treasury Shares to Fund ESOP

438,329 

 

8,454 

 

 

8,043 

16,497 

 

Other Changes in Shareholders' Equity

 

 

8,574 

 

 

 

8,574 

 

Net Income Attributable to Noncontrolling Interests

 

 

 

(103)

 

 

(103)

 

Other Comprehensive Loss

 

 

 

 

(2,168)

 

(2,168)

Balance as of December 31, 2012

314,053,634 

1,662,547 

6,183,267 

1,802,714 

(72,854)

(338,624)

9,237,050 

 

Net Income

 

 

 

793,689 

 

 

793,689 

 

Dividends on Common Shares - $1.47 Per Share

 

 

 

(462,741)

 

 

(462,741)

 

Dividends on Preferred Stock

 

 

 

(7,682)

 

 

(7,682)

 

Issuance of Common Shares, $5 Par Value

560,848 

2,804 

8,274 

 

 

 

11,078 

 

Long-Term Incentive Plan Activity

 

 

(10,748)

 

 

 

(10,748)

 

Issuance of Treasury Shares

659,077 

 

17,381 

 

 

12,087 

29,468 

 

Other Changes in Shareholders' Equity

 

 

(5,409)

 

 

 

(5,409)

 

Other Comprehensive Income

 

 

 

 

26,823 

 

26,823 

Balance as of December 31, 2013

315,273,559 

1,665,351 

6,192,765 

2,125,980 

(46,031)

(326,537)

9,611,528 

 

Net Income

 

 

 

827,065 

 

 

827,065 

 

Dividends on Common Shares - $1.57 Per Share

 

 

 

(496,524)

 

 

(496,524)

 

Dividends on Preferred Stock

 

 

 

(7,519)

 

 

(7,519)

 

Issuance of Common Shares, $5 Par Value

288,941 

1,445 

5,164 

 

 

 

6,609 

 

Long-Term Incentive Plan Activity

 

 

(9,569)

 

 

 

(9,569)

 

Issuance of Treasury Shares

1,420,837 

 

37,817 

 

 

26,070 

63,887 

 

Other Changes in Shareholders' Equity

 

 

9,657 

(341)

 

 

9,316 

 

Other Comprehensive Loss

 

 

 

 

(27,978)

 

(27,978)

Balance as of December 31, 2014

316,983,337 

$ 1,666,796 

$ 6,235,834 

$ 2,448,661 

$ (74,009)

$ (300,467)

$ 9,976,815 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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



























































































66



NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Years Ended December 31,

(Thousands of Dollars)

2014 

 

2013 

 

2012 

 

 

 

 

 

 

 

 

 

 

 

Operating Activities:

 

 

 

 

 

 

 

 

 

Net Income

$

 827,065 

 

$

793,689 

 

$

 533,077 

 

Adjustments to Reconcile Net Income to Net Cash Flows

 

 

 

 

 

 

 

 

 

 

Provided by Operating Activities:

 

 

 

 

 

 

 

 

 

 

 Depreciation

 

 614,657 

 

 

610,777 

 

 

 519,010 

 

 

 Deferred Income Taxes

 

 443,259 

 

 

431,413 

 

 

 292,000 

 

 

 Pension, SERP and PBOP Expense

 

 99,056 

 

 

195,698 

 

 

 218,540 

 

 

 Pension and PBOP Contributions

 

 (211,649)

 

 

(342,184)

 

 

 (295,028)

 

 

 Regulatory Over/(Under) Recoveries, Net

 

 6,853 

 

 

(24,276)

 

 

 (259,853)

 

 

 Amortization of Regulatory Assets, Net

 

 10,704 

 

 

206,322 

 

 

 79,762 

 

 

 Amortization of Rate Reduction Bonds

 

 - 

 

 

42,581 

 

 

 142,019 

 

 

 Proceeds from DOE Damages Claim, Net

 

 132,138 

 

 

 -   

 

 

 - 

 

 

 Other

 

 39,523 

 

 

 56,071 

 

 

 42,852 

 

Changes in Current Assets and Liabilities:

 

 

 

 

 

 

 

 

 

 

 Receivables and Unbilled Revenues, Net

 

 (122,139)

 

 

(163,549)

 

 

 (20,214)

 

 

 Fuel, Materials and Supplies

 

 (41,310)

 

 

(14,811)

 

 

 34,321 

 

 

 Taxes Receivable/Accrued, Net

 

 (323,224)

 

 

(50,950)

 

 

 (5,450)

 

 

 Accounts Payable

 

 144,743 

 

 

(54,619)

 

 

 (128,339)

 

 

 Other Current Assets and Liabilities, Net

 

 15,797 

 

 

(22,623)

 

 

 8,532 

Net Cash Flows Provided by Operating Activities

 

 1,635,473 

 

 

 1,663,539 

 

 

 1,161,229 

 

 

 

 

 

 

 

 

 

 

 

Investing Activities:

 

 

 

 

 

 

 

 

 

Investments in Property, Plant and Equipment

 

 (1,603,744)

 

 

(1,456,787)

 

 

 (1,472,272)

 

Proceeds from Sales of Marketable Securities

 

 488,789 

 

 

627,532 

 

 

 317,294 

 

Purchases of Marketable Securities

 

 (491,220)

 

 

(679,784)

 

 

 (348,629)

 

Other Investing Activities

 

 14,380 

 

 

67,816 

 

 

 35,683 

Net Cash Flows Used in Investing Activities

 

 (1,591,795)

 

 

(1,441,223)

 

 

 (1,467,924)

 

 

 

 

 

 

 

 

 

 

 

Financing Activities:

 

 

 

 

 

 

 

 

 

Cash Dividends on Common Shares

 

 (475,227)

 

 

(462,741)

 

 

 (375,047)

 

Cash Dividends on Preferred Stock

 

 (7,519)

 

 

(7,682)

 

 

 (7,029)

 

Increase/(Decrease) in Short-Term Debt

 

 285,075 

 

 

(397,000)

 

 

 825,000 

 

Issuance of Long-Term Debt

 

 725,000 

 

 

1,680,000 

 

 

 850,000 

 

Retirements of Long-Term Debt

 

 (576,551)

 

 

(929,885)

 

 

 (839,136)

 

Retirements of Rate Reduction Bonds

 

 - 

 

 

(82,139)

 

 

 (114,433)

 

Other Financing Activities

 

 883 

 

 

(25,253)

 

 

 6,529 

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

 

 (48,339)

 

 

(224,700)

 

 

 345,884 

Net (Decrease)/Increase in Cash and Cash Equivalents

 

 (4,661)

 

 

(2,384)

 

 

39,189 

Cash and Cash Equivalents - Beginning of Year

 

 43,364 

 

 

45,748 

 

 

 6,559 

Cash and Cash Equivalents - End of Year

$

 38,703 

 

$

43,364 

 

$

45,748 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 




67


Company Report on Internal Controls Over Financial Reporting


The Connecticut Light and Power Company


Management is responsible for the preparation, integrity, and fair presentation of the accompanying financial statements of The Connecticut Light and Power Company (CL&P or the Company) and of other sections of this annual report.  


Management is responsible for establishing and maintaining adequate internal controls over financial reporting.  The Company's internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.  There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business.  Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment.  


Under the supervision and with the participation of the principal executive officer and principal financial officer, CL&P conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting were effective as of December 31, 2014.


February 25, 2015



























































































68



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Stockholder of The Connecticut Light and Power Company:


We have audited the accompanying balance sheets of The Connecticut Light and Power Company (the "Company") as of December 31, 2014 and 2013, and the related statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2014.  Our audits also included the financial statement schedule listed in the Index at Item 15 of Part IV.  These financial statements and financial statement schedule are the responsibility of the Company's management.  Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.


We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting.  Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.


In our opinion, such financial statements present fairly, in all material respects, the financial position of The Connecticut Light and Power Company as of December 31, 2014 and 2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.  Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.


/s/ Deloitte & Touche LLP


Hartford, Connecticut

February 25, 2015




69



THE CONNECTICUT LIGHT AND POWER COMPANY

BALANCE SHEETS

 

 

 

 

 

 

 

 

 

 

As of December 31,

(Thousands of Dollars)

2014 

 

2013 

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

 

Current Assets:

 

 

 

 

 

 

Cash

$

 2,356 

 

$

 7,237 

 

Receivables, Net

 

 355,140 

 

 

 319,670 

 

Accounts Receivable from Affiliated Companies

 

 16,757 

 

 

 13,777 

 

Unbilled Revenues

 

 102,137 

 

 

 92,401 

 

Taxes Receivable

 

 116,148 

 

 

 20,041 

 

Regulatory Assets

 

 220,344 

 

 

 150,943 

 

Materials and Supplies

 

 46,664 

 

 

 54,606 

 

Prepayments and Other Current Assets

 

 37,822 

 

 

 33,041 

Total Current Assets

 

 897,368 

 

 

 691,716 

 

 

 

 

 

 

 

Property, Plant and Equipment, Net

 

 6,809,664 

 

 

 6,451,259 

 

 

 

 

 

 

 

Deferred Debits and Other Assets:

 

 

 

 

 

 

Regulatory Assets

 

 1,475,508 

 

 

 1,663,147 

 

Other Long-Term Assets

 

 177,568 

 

 

 174,380 

Total Deferred Debits and Other Assets

 

 1,653,076 

 

 

 1,837,527 

 

 

 

 

 

 

 

Total Assets

$

 9,360,108 

 

$

 8,980,502 


LIABILITIES AND CAPITALIZATION

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities:

 

 

 

 

 

 

Notes Payable to NU Parent

$

 133,400 

 

$

 287,300 

 

Long-Term Debt - Current Portion

 

 162,000 

 

 

 150,000 

 

Accounts Payable

 

 272,971 

 

 

 201,047 

 

Accounts Payable to Affiliated Companies

 

 65,594 

 

 

 56,531 

 

Obligations to Third Party Suppliers

 

 73,624 

 

 

 73,914 

 

Regulatory Liabilities

 

 124,722 

 

 

 93,961 

 

Derivative Liabilities

 

 88,459 

 

 

 92,233 

 

Other Current Liabilities

 

 153,420 

 

 

 134,716 

Total Current Liabilities

 

 1,074,190 

 

 

 1,089,702 

 

 

 

 

 

 

 

 

Deferred Credits and Other Liabilities:

 

 

 

 

 

 

Accumulated Deferred Income Taxes

 

 1,642,805 

 

 

 1,510,586 

 

Regulatory Liabilities

 

 81,298 

 

 

 93,757 

 

Derivative Liabilities

 

 406,199 

 

 

 617,072 

 

Accrued Pension, SERP and PBOP

 

 273,854 

 

 

 95,895 

 

Other Long-Term Liabilities

 

 148,844 

 

 

 163,588 

Total Deferred Credits and Other Liabilities

 

 2,553,000 

 

 

 2,480,898 

 

 

 

 

 

 

 

 

Capitalization:

 

 

 

 

 

 

Long-Term Debt

 

 2,679,951 

 

 

 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

 

 1,804,869 

 

 

 1,682,047 

 

 

Retained Earnings

 

 1,072,477 

 

 

 961,482 

 

 

Accumulated Other Comprehensive Loss

 

 (931)

 

 

 (1,387)

 

Common Stockholder's Equity

 

 2,936,767 

 

 

 2,702,494 

Total Capitalization

 

 5,732,918 

 

 

 5,409,902 

 

 

 

 

 

 

 

 

Commitments and Contingencies (Note 11)

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Liabilities and Capitalization

$

 9,360,108 

 

$

 8,980,502 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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



























































































70



THE CONNECTICUT LIGHT AND POWER COMPANY

STATEMENTS OF INCOME

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Years Ended December 31,

(Thousands of Dollars)

2014 

 

2013 

 

2012 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

$

 2,692,582 

 

$

 2,442,341 

 

$

 2,407,449 

 

 

 

 

 

 

 

 

 

 

 

Operating Expenses:

 

 

 

 

 

 

 

 

 

Purchased Power and Transmission

 

 982,876 

 

 

 872,769 

 

 

 858,231 

 

Operations and Maintenance

 

 494,578 

 

 

 523,247 

 

 

 635,733 

 

Depreciation

 

 188,837 

 

 

 177,603 

 

 

 166,853 

 

Amortization of Regulatory Assets, Net

 

 59,336 

 

 

 4,870 

 

 

 14,372 

 

Energy Efficiency Programs

 

 156,335 

 

 

 89,858 

 

 

 89,299 

 

Taxes Other Than Income Taxes

 

 255,370 

 

 

 234,418 

 

 

 215,972 

 

 

Total Operating Expenses

 

 2,137,332 

 

 

 1,902,765 

 

 

 1,980,460 

Operating Income

 

 555,250 

 

 

 539,576 

 

 

 426,989 

 

 

 

 

 

 

 

 

 

 

 

Interest Expense:

 

 

 

 

 

 

 

 

 

Interest on Long-Term Debt

 

 135,656 

 

 

 130,620 

 

 

 124,894 

 

Other Interest

 

 11,765 

 

 

 3,030 

 

 

 8,233 

 

 

Interest Expense

 

 147,421 

 

 

 133,650 

 

 

 133,127 

Other Income, Net

 

 13,376 

 

 

 15,149 

 

 

 10,300 

Income Before Income Tax Expense

 

 421,205 

 

 

 421,075 

 

 

 304,162 

Income Tax Expense

 

 133,451 

 

 

 141,663 

 

 

 94,437 

Net Income

$

 287,754 

 

$

 279,412 

 

$

 209,725 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

STATEMENTS OF COMPREHENSIVE INCOME

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Income

$

 287,754 

 

$

 279,412 

 

$

 209,725 

Other Comprehensive Income, Net of Tax:

 

 

 

 

 

 

 

 

 

Qualified Cash Flow Hedging Instruments

 

 444 

 

 

 444 

 

 

 444 

 

Changes in Unrealized Gains/(Losses) on Other Securities

 

 12 

 

 

 (31)

 

 

Other Comprehensive Income, Net of Tax

 

 456 

 

 

 413 

 

 

 451 

Comprehensive Income

$

 288,210 

 

$

 279,825 

 

$

 210,176 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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



























































































71



THE CONNECTICUT LIGHT AND POWER COMPANY

STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accumulated

Total

 

 

 

 

 

Capital

 

Other

Common

 

 

 

Common Stock

Surplus,

Retained

Comprehensive

Stockholder's

(Thousands of Dollars, Except Stock Information)

Stock

Amount

Paid In

Earnings

Income/(Loss)

Equity

Balance as of January 1, 2012

6,035,205 

$ 60,352 

$ 1,613,503 

$ 735,948 

$ (2,251)

$ 2,407,552 

 

Net Income

 

 

 

209,725 

 

209,725 

 

Dividends on Preferred Stock

 

 

 

(5,559)

 

(5,559)

 

Dividends on Common Stock

 

 

 

(100,486)

 

(100,486)

 

Allocation of Benefits - ESOP

 

 

1,595 

 

 

1,595 

 

Capital Stock Expenses, Net

 

 

51 

 

 

51 

 

Capital Contributions from NU Parent

 

 

25,000 

 

 

25,000 

 

Other Comprehensive Income

 

 

 

 

451 

451 

Balance as of December 31, 2012

6,035,205 

60,352 

1,640,149 

839,628 

(1,800)

2,538,329 

 

Net Income

 

 

 

279,412 

 

279,412 

 

Dividends on Preferred Stock

 

 

 

(5,559)

 

(5,559)

 

Dividends on Common Stock

 

 

 

(151,999)

 

(151,999)

 

Allocation of Benefits - ESOP

 

 

1,847 

 

 

1,847 

 

Capital Stock Expenses, Net

 

 

51 

 

 

51 

 

Capital Contributions from NU Parent

 

 

40,000 

 

 

40,000 

 

Other Comprehensive Income

 

 

 

 

413 

413 

Balance as of December 31, 2013

6,035,205 

60,352 

1,682,047 

961,482 

(1,387)

2,702,494 

 

Net Income

 

 

 

287,754 

 

287,754 

 

Dividends on Preferred Stock

 

 

 

(5,559)

 

(5,559)

 

Dividends on Common Stock

 

 

 

(171,200)

 

(171,200)

 

Allocation of Benefits - ESOP

 

 

2,771 

 

 

2,771 

 

Capital Stock Expenses, Net

 

 

51 

 

 

51 

 

Capital Contributions from NU Parent

 

 

120,000 

 

 

120,000 

 

Other Comprehensive Income

 

 

 

 

456 

456 

Balance as of December 31, 2014

6,035,205 

$ 60,352 

$ 1,804,869 

$ 1,072,477 

$ (931)

$ 2,936,767 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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



























































































72



THE CONNECTICUT LIGHT AND POWER COMPANY

STATEMENTS OF CASH FLOWS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Years Ended December 31,

(Thousands of Dollars)

2014 

 

2013 

 

2012 

 

 

 

 

 

 

 

 

 

 

 

Operating Activities:

 

 

 

 

 

 

 

 

 

Net Income

$

 287,754 

 

$

 279,412 

 

$

 209,725 

 

Adjustments to Reconcile Net Income to Net Cash Flows

 

 

 

 

 

 

 

 

 

 

Provided by Operating Activities:

 

 

 

 

 

 

 

 

 

 

 Depreciation

 

 188,837 

 

 

 177,603 

 

 

 166,853 

 

 

 Deferred Income Taxes

 

 130,949 

 

 

 130,038 

 

 

 140,993 

 

 

 Pension, SERP and PBOP Expense, Net of PBOP Contributions

 

 14,992 

 

 

 24,416 

 

 

 24,062 

 

 

 Regulatory (Under)/Over Recoveries, Net

 

 (20,502)

 

 

 28,298 

 

 

 (100,505)

 

 

 Amortization of Regulatory Assets, Net

 

 59,336 

 

 

 4,870 

 

 

 14,372 

 

 

 Proceeds from DOE Damages Claim

 

 68,610 

 

 

 - 

 

 

 - 

 

 

 Other

 

 (1,342)

 

 

 (3,478)

 

 

 (28,952)

 

Changes in Current Assets and Liabilities:

 

 

 

 

 

 

 

 

 

 

 Receivables and Unbilled Revenues, Net

 

 (78,631)

 

 

 (56,593)

 

 

 (7,741)

 

 

 Materials and Supplies

 

 13,063 

 

 

 9,997 

 

 

 (4,573)

 

 

 Taxes Receivable/Accrued, Net

 

 (126,376)

 

 

 (41,594)

 

 

 15,702 

 

 

 Accounts Payable

 

 68,891 

 

 

 (66,225)

 

 

 (190,240)

 

 

 Other Current Assets and Liabilities, Net

 

 6,838 

 

 

 8,513 

 

 

 (27,803)

Net Cash Flows Provided by Operating Activities

 

 612,419 

 

 

 495,257 

 

 

 211,893 

 

 

 

 

 

 

 

 

 

 

 

Investing Activities:

 

 

 

 

 

 

 

 

 

Investments in Property, Plant and Equipment

 

 (515,710)

 

 

 (434,934)

 

 

 (449,137)

 

Other Investing Activities

 

 12,653 

 

 

 2,650 

 

 

 32,009 

Net Cash Flows Used in Investing Activities

 

 (503,057)

 

 

 (432,284)

 

 

 (417,128)

 

 

 

 

 

 

 

 

 

 

 

Financing Activities:

 

 

 

 

 

 

 

 

 

Cash Dividends on Common Stock

 

 (171,200)

 

 

 (151,999)

 

 

 (100,486)

 

Cash Dividends on Preferred Stock

 

 (5,559)

 

 

 (5,559)

 

 

 (5,559)

 

(Decrease)/Increase in Short-Term Debt

 

 - 

 

 

 (89,000)

 

 

 58,000 

 

(Decrease)/Increase in Notes Payable to NU Parent

 

 (153,900)

 

 

 (117,800)

 

 

 346,575 

 

Issuance of Long-Term Debt

 

 250,000 

 

 

 400,000 

 

 

 - 

 

Retirements of Long-Term Debt

 

 (150,000)

 

 

 (125,000)

 

 

 (116,400)

 

Capital Contributions from NU Parent

 

 120,000 

 

 

 40,000 

 

 

 25,000 

 

Other Financing Activities

 

 (3,584)

 

 

 (6,379)

 

 

 (1,895)

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

 

 (114,243)

 

 

 (55,737)

 

 

 205,235 

Net (Decrease)/Increase in Cash

 

 (4,881)

 

 

 7,236 

 

 

 - 

Cash - Beginning of Year

 

 7,237 

 

 

 1 

 

 

 1 

Cash - End of Year

$

 2,356 

 

$

 7,237 

 

$

 1 

 

 

 

 

 

 

 

 

 

 

 

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




73


Company Report on Internal Controls Over Financial Reporting


NSTAR Electric Company


Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of NSTAR Electric Company and subsidiary (NSTAR Electric or the Company) and of other sections of this annual report.  


Management is responsible for establishing and maintaining adequate internal controls over financial reporting.  The Company's internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.  There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business.  Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment.  


Under the supervision and with the participation of the principal executive officer and principal financial officer, NSTAR Electric conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting were effective as of December 31, 2014.


February 25, 2015




74


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Stockholder of NSTAR Electric Company:


We have audited the accompanying consolidated balance sheets of NSTAR Electric Company and subsidiary (the "Company") as of December 31, 2014 and 2013 and the related consolidated statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2014.  Our audits also included the financial statement schedule listed in the Index at Item 15 of Part IV.  These financial statements and financial statement schedule are the responsibility of the Company's management.  Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.


We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting.  Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.


In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of NSTAR Electric Company and subsidiary as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.  Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.


/s/ Deloitte & Touche LLP


Hartford, Connecticut

February 25, 2015




75



NSTAR ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS

 

 

 

 

 

 

 

 

 

 

As of December 31,

(Thousands of Dollars)

2014 

 

2013 

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

 

Current Assets:

 

 

 

 

 

 

Cash and Cash Equivalents

$

 12,773 

 

$

 8,021 

 

Receivables, Net

 

 234,481 

 

 

 209,711 

 

Accounts Receivable from Affiliated Companies

 

 40,353 

 

 

 27,264 

 

Unbilled Revenues

 

 29,741 

 

 

 41,368 

 

Taxes Receivable

 

 144,601 

 

 

 25,590 

 

Materials and Supplies

 

 74,179 

 

 

 44,236 

 

Regulatory Assets

 

 198,710 

 

 

 204,144 

 

Prepayments and Other Current Assets

 

 10,815 

 

 

 11,120 

Total Current Assets

 

 745,653 

 

 

 571,454 

 

 

 

 

 

 

 

Property, Plant and Equipment, Net

 

 5,335,436 

 

 

 5,043,887 

 

 

 

 

 

 

 

Deferred Debits and Other Assets:

 

 

 

 

 

 

Regulatory Assets

 

 1,179,100 

 

 

 1,235,156 

 

Other Long-Term Assets

 

 73,051 

 

 

 60,624 

Total Deferred Debits and Other Assets

 

 1,252,151 

 

 

 1,295,780 

 

 

 

 

 

 

 

Total Assets

$

 7,333,240 

 

$

 6,911,121 


LIABILITIES AND CAPITALIZATION

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities:

 

 

 

 

 

 

Notes Payable

$

 302,000 

 

$

103,500 

 

Long-Term Debt - Current Portion

 

 4,700 

 

 

 301,650 

 

Accounts Payable

 

 217,311 

 

 

 202,100 

 

Accounts Payable to Affiliated Companies

 

 63,517 

 

 

 75,707 

 

Accumulated Deferred Income Taxes

 

 55,136 

 

 

 50,128 

 

Regulatory Liabilities

 

 49,611 

 

 

 53,958 

 

Other Current Liabilities

 

 186,513 

 

 

 123,869 

Total Current Liabilities

 

 878,788 

 

 

 910,912 

 

 

 

 

 

 

 

 

Deferred Credits and Other Liabilities:

 

 

 

 

 

 

Accumulated Deferred Income Taxes

 

 1,527,667 

 

 

 1,466,835 

 

Regulatory Liabilities

 

 262,738 

 

 

 253,108 

 

Accrued Pension, SERP and PBOP

 

 235,529 

 

 

 118,010 

 

Other Long-Term Liabilities

 

 129,279 

 

 

 206,386 

Total Deferred Credits and Other Liabilities

 

 2,155,213 

 

 

 2,044,339 

 

 

 

 

 

 

 

 

Capitalization:

 

 

 

 

 

 

Long-Term Debt

 

 1,792,712 

 

 

 1,499,417 

 

 

 

 

 

 

 

 

   Preferred Stock Not Subject to Mandatory Redemption

 

 43,000 

 

 

 43,000 

 

 

 

 

 

 

 

 

 

Common Stockholder's Equity:

 

 

 

 

 

 

 

Common Stock

 

 - 

 

 

 - 

 

 

Capital Surplus, Paid In

 

 994,130 

 

 

 992,625 

 

 

Retained Earnings

 

 1,468,955 

 

 

 1,420,828 

 

 

Accumulated Other Comprehensive Income

 

 442 

 

 

 - 

 

Common Stockholder's Equity

 

 2,463,527 

 

 

 2,413,453 

Total Capitalization

 

 4,299,239 

 

 

 3,955,870 

 

 

 

 

 

 

 

 

Commitments and Contingencies (Note 11)

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Liabilities and Capitalization

$

 7,333,240 

 

$

 6,911,121 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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



























































































76



NSTAR ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF INCOME

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Years Ended December 31,

(Thousands of Dollars)

2014 

 

2013 

 

2012 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

$

 2,536,677 

 

$

 2,493,479 

 

$

 2,300,997 

 

 

 

 

 

 

 

 

 

 

 

Operating Expenses:

 

 

 

 

 

 

 

 

 

Purchased Power and Transmission

 

 1,122,298 

 

 

 849,149 

 

 

 788,252 

 

Operations and Maintenance

 

 326,972 

 

 

 376,360 

 

 

 431,802 

 

Depreciation

 

 188,693 

 

 

 180,298 

 

 

 171,070 

 

Amortization of Regulatory Assets/(Liabilities), Net

 

 (6,330)

 

 

 230,148 

 

 

 117,682 

 

Amortization of Rate Reduction Bonds

 

 - 

 

 

 15,054 

 

 

 90,322 

 

Energy Efficiency Programs

 

 193,516 

 

 

 206,536 

 

 

 201,234 

 

Taxes Other Than Income Taxes

 

 133,072 

 

 

 127,778 

 

 

 119,219 

 

 

Total Operating Expenses

 

 1,958,221 

 

 

 1,985,323 

 

 

 1,919,581 

Operating Income

 

 578,456 

 

 

 508,156 

 

 

 381,416 

 

 

 

 

 

 

 

 

 

 

 

Interest Expense:

 

 

 

 

 

 

 

 

 

Interest on Long-Term Debt

 

 77,140 

 

 

 79,088 

 

 

 87,100 

 

Interest on Rate Reduction Bonds

 

 - 

 

 

 399 

 

 

 3,585 

 

Other Interest

 

 738 

 

 

 (9,104)

 

 

 (20,631)

 

 

Interest Expense

 

 77,878 

 

 

 70,383 

 

 

 70,054 

Other Income, Net

 

 4,491 

 

 

 3,639 

 

 

 2,846 

Income Before Income Tax Expense

 

 505,069 

 

 

 441,412 

 

 

 314,208 

Income Tax Expense

 

 201,981 

 

 

 172,866 

 

 

 123,966 

Net Income

$

 303,088 

 

$

 268,546 

 

$

 190,242 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 

 

 

 

 

 

 

 

 

 

 

Net Income

$

 303,088 

 

$

 268,546 

 

$

 190,242 

Other Comprehensive Income, Net of Tax:

 

 

 

 

 

 

 

 

 

 

Changes in Funded Status of SERP Benefit Plan

 

 442 

 

 

 - 

 

 

 - 

Other Comprehensive Income, Net of Tax

 

 442 

 

 

 - 

 

 

 - 

Comprehensive Income

$

 303,530 

 

$

 268,546 

 

$

 190,242 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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



























































































77



NSTAR ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accumulated

Total

 

 

 

 

 

Capital

 

Other

Common

 

 

 

Common Stock

Surplus,

Retained

Comprehensive

Stockholder's

(Thousands of Dollars, Except Stock Information)

Stock

Amount

Paid In

Earnings

Income

Equity

Balance as of January 1, 2012

100 

$ - 

$ 992,625 

$ 1,239,123 

$ - 

$ 2,231,748 

 

Net Income

 

 

 

190,242 

 

190,242 

 

Dividends on Preferred Stock

 

 

 

(1,960)

 

(1,960)

 

Dividends on Common Stock

 

 

 

(217,000)

 

(217,000)

Balance as of December 31, 2012

100 

992,625 

1,210,405 

2,203,030 

 

Net Income

 

 

 

268,546 

 

268,546 

 

Dividends on Preferred Stock

 

 

 

(2,123)

 

(2,123)

 

Dividends on Common Stock

 

 

 

(56,000)

 

(56,000)

Balance as of December 31, 2013

100 

992,625 

1,420,828 

2,413,453 

 

Net Income

 

 

 

303,088 

 

303,088 

 

Dividends on Preferred Stock

 

 

 

(1,961)

 

(1,961)

 

Dividends on Common Stock

 

 

 

(253,000)

 

(253,000)

 

Other Changes in Stockholder's Equity

 

 

1,505 

 

 

1,505 

 

Accumulated Other Comprehensive Income

 

 

 

 

442 

442 

Balance as of December 31, 2014

100 

$ - 

$ 994,130 

$ 1,468,955 

$ 442 

$ 2,463,527 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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



























































































78



NSTAR ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Years Ended December 31,

(Thousands of Dollars)

2014 

 

2013 

 

2012 

 

 

 

 

 

 

 

 

 

 

 

Operating Activities:

 

 

 

 

 

 

 

 

 

Net Income

$

 303,088 

 

$

 268,546 

 

$

 190,242 

 

Adjustments to Reconcile Net Income to Net Cash Flows

 

 

 

 

 

 

 

 

 

 

Provided by Operating Activities:

 

 

 

 

 

 

 

 

 

 

 Depreciation

 

 188,693 

 

 

 180,298 

 

 

 171,070 

 

 

 Deferred Income Taxes

 

 108,133 

 

 

 48,808 

 

 

 4,264 

 

 

 Pension and PBOP Expense

 

 6,760 

 

 

 35,731 

 

 

 66,010 

 

 

 Pension and PBOP Contributions

 

 (120,306)

 

 

 (82,000)

 

 

 (25,000)

 

 

 Regulatory Over/(Under) Recoveries, Net

 

 57,696 

 

 

 (119,433)

 

 

 (16,129)

 

 

 Amortization of Regulatory (Liabilities)/Assets, Net

 

 (6,330)

 

 

 230,148 

 

 

 117,682 

 

 

 Amortization of Rate Reduction Bonds

 

 - 

 

 

 15,054 

 

 

 90,322 

 

 

 Bad Debt Expense

 

 24,740 

 

 

 28,108 

 

 

 40,301 

 

 

 Proceeds from DOE Damages Claim

 

 30,193 

 

 

 - 

 

 

 - 

 

 

 Other

 

 (51,478)

 

 

 4,428 

 

 

 (32,048)

 

Changes in Current Assets and Liabilities:

 

 

 

 

 

 

 

 

 

 

 Receivables and Unbilled Revenues, Net

 

 (18,853)

 

 

 (45,405)

 

 

 (10,496)

 

 

 Materials and Supplies

 

 (29,943)

 

 

 3,227 

 

 

 1,813 

 

 

 Taxes Receivable/Accrued, Net

 

 (122,746)

 

 

 (38,003)

 

 

 29,899 

 

 

 Accounts Payable

 

 9,753 

 

 

 31,875 

 

 

 2,662 

 

 

 Accounts Receivable from/Payable to Affiliates, Net

 

 115,092 

 

 

 (44,491)

 

 

 (61,879)

 

 

 Other Current Assets and Liabilities, Net

 

 38,535 

 

 

 (6,468)

 

 

 22,568 

Net Cash Flows Provided by Operating Activities

 

 533,027 

 

 

 510,423 

 

 

 591,281 

 

 

 

 

 

 

 

 

 

 

 

Investing Activities:

 

 

 

 

 

 

 

 

 

Investments in Property, Plant and Equipment

 

 (465,028)

 

 

 (476,600)

 

 

 (414,089)

 

Decrease in Special Deposits

 

 - 

 

 

 37,604 

 

 

 3,060 

 

Other Investing Activities

 

 - 

 

 

 400 

 

 

 400 

Net Cash Flows Used in Investing Activities

 

 (465,028)

 

 

 (438,596)

 

 

 (410,629)

 

 

 

 

 

 

 

 

 

 

 

Financing Activities:

 

 

 

 

 

 

 

 

 

Cash Dividends on Common Stock

 

 (253,000)

 

 

 (56,000)

 

 

 (217,000)

 

Cash Dividends on Preferred Stock

 

 (1,961)

 

 

 (2,123)

 

 

 (1,960)

 

Increase/(Decrease) in Short-Term Debt

 

 198,500 

 

 

 (172,500)

 

 

 134,500 

 

Issuance of Long-Term Debt

 

 300,000 

 

 

 200,000 

 

 

 400,000 

 

Retirements of Long-Term Debt

 

 (301,650)

 

 

 (1,650)

 

 

 (401,650)

 

Retirements of Rate Reduction Bonds

 

 - 

 

 

 (43,493)

 

 

 (84,367)

 

Other Financing Activities

 

 (5,136)

 

 

 (1,735)

 

 

 (5,853)

Net Cash Flows Used in Financing Activities

 

 (63,247)

 

 

 (77,501)

 

 

 (176,330)

Net Increase/(Decrease) in Cash and Cash Equivalents

 

 4,752 

 

 

 (5,674)

 

 

 4,322 

Cash and Cash Equivalents - Beginning of Year

 

 8,021 

 

 

 13,695 

 

 

 9,373 

Cash and Cash Equivalents - End of Year

$

 12,773 

 

$

 8,021 

 

$

 13,695 

 

 

 

 

 

 

 

 

 

 

 

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




79


Company Report on Internal Controls Over Financial Reporting


Public Service Company of New Hampshire


Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of Public Service Company of New Hampshire and subsidiary (PSNH or the Company) and of other sections of this annual report.  


Management is responsible for establishing and maintaining adequate internal controls over financial reporting.  The Company's internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.  There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business.  Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment.  


Under the supervision and with the participation of the principal executive officer and principal financial officer, PSNH conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting were effective as of December 31, 2014.



February 25, 2015




80


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Stockholder of Public Service Company of New Hampshire:


We have audited the accompanying consolidated balance sheets of Public Service Company of New Hampshire and subsidiary (the "Company") as of December 31, 2014 and 2013 and the related consolidated statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2014.  Our audits also included the financial statement schedule listed in the Index at Item 15 of Part IV.  These financial statements and financial statement schedule are the responsibility of the Company's management.  Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.


We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting.  Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.


In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Public Service Company of New Hampshire and subsidiary as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.  Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.


/s/ Deloitte & Touche LLP


Hartford, Connecticut

February 25, 2015



81



PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY

 

 

 

 

 

CONSOLIDATED BALANCE SHEETS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31,

(Thousands of Dollars)

2014 

 

2013 

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

 

Current Assets:

 

 

 

 

 

 

Cash

$

 489 

 

$

 130 

 

Receivables, Net

 

 80,151 

 

 

 76,331 

 

Accounts Receivable from Affiliated Companies

 

 3,194 

 

 

 90 

 

Unbilled Revenues

 

 40,181 

 

 

 38,344 

 

Fuel, Materials and Supplies

 

 148,139 

 

 

 128,736 

 

Regulatory Assets

 

 111,705 

 

 

 92,194 

 

Prepayments and Other Current Assets

 

 42,392 

 

 

 24,100 

Total Current Assets

 

 426,251 

 

 

 359,925 

 

 

 

 

 

 

 

Property, Plant and Equipment, Net

 

 2,635,844 

 

 

 2,467,556 

 

 

 

 

 

 

 

Deferred Debits and Other Assets:

 

 

 

 

 

 

Regulatory Assets

 

 293,115 

 

 

 219,346 

 

Other Long-Term Assets

 

 39,228 

 

 

 39,891 

Total Deferred Debits and Other Assets

 

 332,343 

 

 

 259,237 

 

 

 

 

 

 

 

Total Assets

$

 3,394,438 

 

$

 3,086,718 


LIABILITIES AND CAPITALIZATION

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities:

 

 

 

 

 

 

Notes Payable to NU Parent

$

 90,500 

 

$

 86,500 

 

Long-Term Debt - Current Portion

 

 - 

 

 

 50,000 

 

Accounts Payable

 

 93,349 

 

 

 82,920 

 

Accounts Payable to Affiliated Companies

 

 33,734 

 

 

 22,040 

 

Regulatory Liabilities

 

 16,044 

 

 

 20,643 

 

Accumulated Deferred Income Taxes

 

 36,164 

 

 

 28,596 

 

Other Current Liabilities

 

 38,969 

 

 

 51,729 

Total Current Liabilities

 

 308,760 

 

 

 342,428 

 

 

 

 

 

 

 

 

Deferred Credits and Other Liabilities:

 

 

 

 

 

 

Accumulated Deferred Income Taxes

 

 587,292 

 

 

 500,166 

 

Regulatory Liabilities

 

 51,372 

 

 

 51,723 

 

Accrued Pension, SERP and PBOP

 

 93,243 

 

 

 15,272 

 

Other Long-Term Liabilities

 

 50,155 

 

 

 46,247 

Total Deferred Credits and Other Liabilities

 

 782,062 

 

 

 613,408 

 

 

 

 

 

 

 

 

Capitalization:

 

 

 

 

 

 

Long-Term Debt

 

 1,076,286 

 

 

 999,006 

 

 

 

 

 

 

 

 

 

Common Stockholder's Equity:

 

 

 

 

 

 

 

Common Stock

 

 - 

 

 

 - 

 

 

Capital Surplus, Paid In

 

 748,240 

 

 

 701,911 

 

 

Retained Earnings

 

 486,459 

 

 

 438,515 

 

 

Accumulated Other Comprehensive Loss

 

 (7,369)

 

 

 (8,550)

 

Common Stockholder's Equity

 

 1,227,330 

 

 

 1,131,876 

Total Capitalization

 

 2,303,616 

 

 

 2,130,882 

 

 

 

 

 

 

 

 

Commitments and Contingencies (Note 11)

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Liabilities and Capitalization

$

 3,394,438 

 

$

 3,086,718 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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



























































































82



PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY

 

 

 

CONSOLIDATED STATEMENTS OF INCOME

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Years Ended December 31,

(Thousands of Dollars)

2014 

 

2013 

 

2012 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

$

 959,500 

 

$

 935,402 

 

$

 988,013 

 

 

 

 

 

 

 

 

 

 

 

Operating Expenses:

 

 

 

 

 

 

 

 

 

Purchased Power, Fuel and Transmission

 

 313,732 

 

 

 269,754 

 

 

 319,253 

 

Operations and Maintenance

 

 261,848 

 

 

 267,797 

 

 

 263,234 

 

Depreciation

 

 98,436 

 

 

 91,581 

 

 

 87,602 

 

Amortization of Regulatory Liabilities, Net

 

 (29,602)

 

 

 (20,387)

 

 

 (24,086)

 

Amortization of Rate Reduction Bonds

 

 - 

 

 

 19,748 

 

 

 56,645 

 

Energy Efficiency Programs

 

 14,286 

 

 

 14,494 

 

 

 14,245 

 

Taxes Other Than Income Taxes

 

 71,417 

 

 

 67,196 

 

 

 66,025 

 

 

Total Operating Expenses

 

 730,117 

 

 

 710,183 

 

 

 782,918 

Operating Income

 

 229,383 

 

 

 225,219 

 

 

 205,095 

 

 

 

 

 

 

 

 

 

 

 

Interest Expense:

 

 

 

 

 

 

 

 

 

Interest on Long-Term Debt

 

 45,116 

 

 

 44,370 

 

 

 46,228 

 

Interest on Rate Reduction Bonds

 

 - 

 

 

 (154)

 

 

 2,687 

 

Other Interest

 

 233 

 

 

 1,960 

 

 

 1,313 

 

 

Interest Expense

 

 45,349 

 

 

 46,176 

 

 

 50,228 

Other Income, Net

 

 2,045 

 

 

 3,455 

 

 

 3,008 

Income Before Income Tax Expense

 

 186,079 

 

 

 182,498 

 

 

 157,875 

Income Tax Expense

 

 72,135 

 

 

 71,101 

 

 

 60,993 

Net Income

$

 113,944 

 

$

 111,397 

 

$

 96,882 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 

 

 

 

 

 

 

 

 

 

 

Net Income

$

 113,944 

 

$

 111,397 

 

$

 96,882 

Other Comprehensive Income, Net of Tax:

 

 

 

 

 

 

 

 

 

Qualified Cash Flow Hedging Instruments

 

 1,162 

 

 

1,162 

 

 

1,162 

 

Changes in Unrealized Gains/(Losses) on Other Securities

 

 19 

 

 

(54)

 

 

13 

 

Changes in Funded Status of SERP Benefit Plan

 

 - 

 

 

 (3)

 

 

 2 

Other Comprehensive Income, Net of Tax

 

 1,181 

 

 

 1,105 

 

 

 1,177 

Comprehensive Income

$

 115,125 

 

$

 112,502 

 

$

 98,059 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 



























































































83



PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accumulated

Total

 

 

 

 

 

Capital

 

Other

Common

 

 

 

Common Stock

Surplus,

Retained

Comprehensive

Stockholder's

(Thousands of Dollars, Except Stock Information)

Stock

Amount

Paid In

Earnings

Income/(Loss)

Equity

Balance as of January 1, 2012

301 

$ - 

$ 700,285 

$ 388,910 

$ (10,832)

$ 1,078,363 

 

Net Income

 

 

 

96,882 

 

96,882 

 

Dividends on Common Stock

 

 

 

(90,674)

 

(90,674)

 

Allocation of Benefits - ESOP

 

 

767 

 

 

767 

 

Other Comprehensive Income

 

 

 

 

1,177 

1,177 

Balance as of December 31, 2012

301 

 - 

701,052 

395,118 

(9,655)

1,086,515 

 

Net Income

 

 

 

111,397 

 

111,397 

 

Dividends on Common Stock

 

 

 

(68,000)

 

(68,000)

 

Allocation of Benefits - ESOP

 

 

859 

 

 

859 

 

Other Comprehensive Income

 

 

 

 

1,105 

1,105 

Balance as of December 31, 2013

301 

 - 

701,911 

438,515 

(8,550)

1,131,876 

 

Net Income

 

 

 

113,944 

 

113,944 

 

Dividends on Common Stock

 

 

 

(66,000)

 

(66,000)

 

Capital Contributions from NU Parent

 

 

45,000 

 

 

45,000 

 

Allocation of Benefits - ESOP

 

 

1,329 

 

 

1,329 

 

Other Comprehensive Income

 

 

 

 

1,181 

1,181 

Balance as of December 31, 2014

301 

$ - 

$ 748,240 

$ 486,459 

$ (7,369)

$ 1,227,330 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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



























































































84



PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Years Ended December 31,

(Thousands of Dollars)

2014 

 

2013 

 

2012 

 

 

 

 

 

 

 

 

 

 

 

Operating Activities:

 

 

 

 

 

 

 

 

 

Net Income

$

 113,944 

 

$

 111,397 

 

$

 96,882 

 

Adjustments to Reconcile Net Income to Net Cash Flows

 

 

 

 

 

 

 

 

 

 

Provided by Operating Activities:

 

 

 

 

 

 

 

 

 

 

 Depreciation

 

 98,436 

 

 

 91,581 

 

 

 87,602 

 

 

 Deferred Income Taxes

 

 94,813 

 

 

 75,693 

 

 

 58,552 

 

 

 Pension, SERP and PBOP Expense

 

 7,197 

 

 

 26,846 

 

 

 26,312 

 

 

 Pension and PBOP Contributions

 

 (2,482)

 

 

 (112,964)

 

 

 (96,880)

 

 

 Regulatory Underrecoveries, Net

 

 (11,875)

 

 

 (8,481)

 

 

 (183)

 

 

 Amortization of Regulatory Liabilities, Net

 

 (29,602)

 

 

 (20,387)

 

 

 (24,086)

 

 

 Amortization of Rate Reduction Bonds

 

 - 

 

 

 19,748 

 

 

 56,645 

 

 

 Proceeds from DOE Damages Claim

 

 14,453 

 

 

 - 

 

 

 - 

 

 

 Other

 

 10,095 

 

 

 16,079 

 

 

 11,205 

 

Changes in Current Assets and Liabilities:

 

 

 

 

 

 

 

 

 

 

 Receivables and Unbilled Revenues, Net

 

 (15,576)

 

 

 2,412 

 

 

 (84)

 

 

 Fuel, Materials and Supplies

 

 (19,403)

 

 

 (33,391)

 

 

 25,897 

 

 

 Taxes Receivable/Accrued, Net

 

 (23,857)

 

 

 26,462 

 

 

 (9,752)

 

 

 Accounts Payable

 

 17,796 

 

 

 2,632 

 

 

 (15,248)

 

 

 Other Current Assets and Liabilities, Net

 

 (5,972)

 

 

 (9,520)

 

 

 13,436 

Net Cash Flows Provided by Operating Activities

 

 247,967 

 

 

 188,107 

 

 

 230,298 

 

 

 

 

 

 

 

 

 

 

 

Investing Activities:

 

 

 

 

 

 

 

 

 

Investments in Property, Plant and Equipment

 

 (256,159)

 

 

 (186,009)

 

 

 (203,902)

 

Decrease in Notes Receivable from Affiliate

 

 - 

 

 

 - 

 

 

 55,900 

 

(Increase)/Decrease in Special Deposits

 

 (1,013)

 

 

 22,040 

 

 

 4,200 

 

Other Investing Activities

 

 (139)

 

 

 (88)

 

 

 (135)

Net Cash Flows Used in Investing Activities

 

 (257,311)

 

 

 (164,057)

 

 

 (143,937)

 

 

 

 

 

 

 

 

 

 

 

Financing Activities:

 

 

 

 

 

 

 

 

 

Cash Dividends on Common Stock

 

 (66,000)

 

 

 (68,000)

 

 

 (90,674)

 

Increase in Short-Term Debt

 

 4,000 

 

 

 23,200 

 

 

 - 

 

Issuance of Long-Term Debt

 

 75,000 

 

 

 250,000 

 

 

 - 

 

Retirements of Long-Term Debt

 

 (50,000)

 

 

 (198,235)

 

 

 - 

 

Retirements of Rate Reduction Bonds

 

 - 

 

 

 (29,294)

 

 

 (56,074)

 

Increase in Notes Payable to NU Parent

 

 - 

 

 

 - 

 

 

 63,300 

 

Capital Contributions from NU Parent

 

 45,000 

 

 

 - 

 

 

 - 

 

Other Financing Activities

 

 1,703 

 

 

 (4,084)

 

 

 (476)

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

 

 9,703 

 

 

 (26,413)

 

 

 (83,924)

Net Increase/(Decrease) in Cash

 

 359 

 

 

 (2,363)

 

 

 2,437 

Cash - Beginning of Year

 

 130 

 

 

 2,493 

 

 

 56 

Cash - End of Year

$

 489 

 

$

 130 

 

$

 2,493 

 

 

 

 

 

 

 

 

 

 

 

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




85


Company Report on Internal Controls Over Financial Reporting


Western Massachusetts Electric Company


Management is responsible for the preparation, integrity, and fair presentation of the accompanying financial statements of Western Massachusetts Electric Company (WMECO or the Company) and of other sections of this annual report.  


Management is responsible for establishing and maintaining adequate internal controls over financial reporting.  The Company's internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.  There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business.  Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment.  


Under the supervision and with the participation of the principal executive officer and principal financial officer, WMECO conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting were effective as of December 31, 2014.


February 25, 2015




86


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Stockholder of Western Massachusetts Electric Company:


We have audited the accompanying balance sheets of Western Massachusetts Electric Company (the "Company") as of December 31, 2014 and 2013 and the related statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2014.  Our audits also included the financial statement schedule listed in the Index at Item 15 of Part IV.  These financial statements and financial statement schedule are the responsibility of the Company's management.  Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.


We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting.  Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.


In our opinion, such financial statements present fairly, in all material respects, the financial position of Western Massachusetts Electric Company as of December 31, 2014 and 2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.  Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.


/s/ Deloitte & Touche LLP


Hartford, Connecticut

February 25, 2015



























































































87



WESTERN MASSACHUSETTS ELECTRIC COMPANY

BALANCE SHEETS

 

 

 

 

 

 

 

 

 

 

As of December 31,

(Thousands of Dollars)

2014 

 

2013 

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

 

Current Assets:

 

 

 

 

 

 

Receivables, Net

$

 51,066 

 

$

 49,018 

 

Accounts Receivable from Affiliated Companies

 

 7,851 

 

 

 47,607 

 

Unbilled Revenues

 

 15,146 

 

 

 16,562 

 

Taxes Receivable

 

 18,126 

 

 

 432 

 

Regulatory Assets

 

 51,923 

 

 

 43,024 

 

Marketable Securities

 

 28,658 

 

 

 26,628 

 

Prepayments and Other Current Assets

 

 7,607 

 

 

 10,479 

Total Current Assets

 

 180,377 

 

 

 193,750 

 

 

 

 

 

 

 

Property, Plant and Equipment, Net

 

 1,461,321 

 

 

 1,381,060 

 

 

 

 

 

 

 

Deferred Debits and Other Assets:

 

 

 

 

 

 

Regulatory Assets

 

 146,307 

 

 

 146,088 

 

Marketable Securities

 

 29,452 

 

 

 31,243 

 

Other Long-Term Assets

 

 22,018 

 

 

 40,679 

Total Deferred Debits and Other Assets

 

 197,777 

 

 

 218,010 

 

 

 

 

 

 

 

Total Assets

$

 1,839,475 

 

$

 1,792,820 


LIABILITIES AND CAPITALIZATION

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities:

 

 

 

 

 

 

Notes Payable to NU Parent

$

 21,400 

 

$

 - 

 

Long-Term Debt - Current Portion

 

 50,000 

 

 

 - 

 

Accounts Payable

 

 53,732 

 

 

 62,961 

 

Accounts Payable to Affiliated Companies

 

 14,328 

 

 

 9,230 

 

Accrued Interest

 

 7,526 

 

 

 7,525 

 

Regulatory Liabilities

 

 22,486 

 

 

 19,858 

 

Accumulated Deferred Income Taxes

 

 18,089 

 

 

 13,098 

 

Counterparty Deposits

 

 3,376 

 

 

 7,688 

 

Other Current Liabilities

 

 13,178 

 

 

 20,629 

Total Current Liabilities

 

 204,115 

 

 

 140,989 

 

 

 

 

 

 

 

 

Deferred Credits and Other Liabilities:

 

 

 

 

 

 

Accumulated Deferred Income Taxes

 

 416,822 

 

 

 396,933 

 

Regulatory Liabilities

 

 10,835 

 

 

 13,873 

 

Accrued Pension, SERP and PBOP

 

 17,705 

 

 

 3,911 

 

Other Long-Term Liabilities

 

 33,747 

 

 

 28,619 

Total Deferred Credits and Other Liabilities

 

 479,109 

 

 

 443,336 

 

 

 

 

 

 

 

 

Capitalization:

 

 

 

 

 

 

Long-Term Debt

 

 578,471 

 

 

 629,389 

 

 

 

 

 

 

 

 

 

Common Stockholder's Equity:

 

 

 

 

 

 

 

Common Stock

 

 10,866 

 

 

 10,866 

 

 

Capital Surplus, Paid In

 

 391,256 

 

 

 390,743 

 

 

Retained Earnings

 

 178,834 

 

 

 181,014 

 

 

Accumulated Other Comprehensive Loss

 

 (3,176)

 

 

 (3,517)

 

Common Stockholder's Equity

 

 577,780 

 

 

 579,106 

Total Capitalization

 

 1,156,251 

 

 

 1,208,495 

 

 

 

 

 

 

 

 

Commitments and Contingencies (Note 11)

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Liabilities and Capitalization

$

 1,839,475 

 

$

 1,792,820 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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



























































































88



WESTERN MASSACHUSETTS ELECTRIC COMPANY

STATEMENTS OF INCOME

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Years Ended December 31,

(Thousands of Dollars)

2014 

 

2013 

 

2012 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

$

 493,423 

 

$

 472,724 

 

$

 441,164 

 

 

 

 

 

 

 

 

 

 

 

Operating Expenses:

 

 

 

 

 

 

 

 

 

Purchased Power and Transmission

 

 172,876 

 

 

 147,059 

 

 

 136,086 

 

Operations and Maintenance

 

 89,406 

 

 

 96,194 

 

 

 97,031 

 

Depreciation

 

 41,886 

 

 

 37,568 

 

 

 29,971 

 

Amortization of Regulatory Assets/(Liabilities), Net

 

 (6,228)

 

 

 (3,206)

 

 

 410 

 

Amortization of Rate Reduction Bonds

 

 - 

 

 

 7,780 

 

 

 17,632 

 

Energy Efficiency Programs

 

 42,937 

 

 

 39,524 

 

 

 27,802 

 

Taxes Other Than Income Taxes

 

 34,907 

 

 

 28,458 

 

 

 21,458 

 

 

Total Operating Expenses

 

 375,784 

 

 

 353,377 

 

 

 330,390 

Operating Income

 

 117,639 

 

 

 119,347 

 

 

 110,774 

 

 

 

 

 

 

 

 

 

 

 

Interest Expense:

 

 

 

 

 

 

 

 

 

Interest on Long-Term Debt

 

 24,245 

 

 

 23,625 

 

 

 23,462 

 

Interest on Rate Reduction Bonds

 

 - 

 

 

 177 

 

 

 1,229 

 

Other Interest

 

 686 

 

 

 1,049 

 

 

 1,943 

 

 

Interest Expense

 

 24,931 

 

 

 24,851 

 

 

 26,634 

Other Income, Net

 

 2,379 

 

 

 3,310 

 

 

 2,503 

Income Before Income Tax Expense

 

 95,087 

 

 

 97,806 

 

 

 86,643 

Income Tax Expense

 

 37,268 

 

 

 37,368 

 

 

 32,140 

Net Income

$

 57,819 

 

$

 60,438 

 

$

 54,503 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

STATEMENTS OF COMPREHENSIVE INCOME

 

 

 

 

 

 

 

 

 

 

 

Net Income

$

 57,819 

 

$

 60,438 

 

$

 54,503 

Other Comprehensive Income/(Loss), Net of Tax:

 

 

 

 

 

 

 

 

 

Qualified Cash Flow Hedging Instruments

 

 338 

 

 

 338 

 

 

338 

 

Changes in Unrealized Gains/(Losses) on Other Securities

 

 3 

 

 

 (9)

 

 

Other Comprehensive Income/(Loss), Net of Tax

 

 341 

 

 

 329 

 

 

 340 

Comprehensive Income

$

 58,160 

 

$

 60,767 

 

$

 54,843 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 



























































































89



WESTERN MASSACHUSETTS  ELECTRIC COMPANY

STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accumulated

Total

 

 

 

 

 

Capital

 

Other

Common

 

 

 

Common Stock

Surplus,

Retained

Comprehensive

Stockholder's

(Thousands of Dollars, Except Stock Information)

Stock

Amount

Paid In

Earnings

Income/(Loss)

Equity

Balance as of January 1, 2012

434,653 

$ 10,866 

$ 340,115 

$ 115,506 

$ (4,186)

$ 462,301 

 

Net Income

 

 

 

 54,503 

 

54,503 

 

Dividends on Common Stock

 

 

 

(9,432)

 

(9,432)

 

Allocation of Benefits - ESOP

 

 

297 

 

 

297 

 

Capital Contributions from NU Parent

 

 

50,000 

 

 

50,000 

 

Other Comprehensive Income

 

 

 

 

340 

340 

Balance as of December 31, 2012

434,653 

10,866 

390,412 

160,577 

(3,846)

558,009 

 

Net Income

 

 

 

 60,438 

 

60,438 

 

Dividends on Common Stock

 

 

 

(40,001)

 

(40,001)

 

Allocation of Benefits - ESOP

 

 

331 

 

 

331 

 

Other Comprehensive Income

 

 

 

 

329 

329 

Balance as of December 31, 2013

434,653 

10,866 

390,743 

181,014 

(3,517)

579,106 

 

Net Income

 

 

 

 57,819 

 

57,819 

 

Dividends on Common Stock

 

 

 

(59,999)

 

(59,999)

 

Allocation of Benefits - ESOP

 

 

513 

 

 

513 

 

Other Comprehensive Income

 

 

 

 

341 

341 

Balance as of December 31, 2014

434,653 

$ 10,866 

$ 391,256 

$ 178,834 

$ (3,176)

$ 577,780 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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



























































































90



WESTERN MASSACHUSETTS ELECTRIC COMPANY

STATEMENTS OF CASH FLOWS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Years Ended December 31,

(Thousands of Dollars)

2014 

 

2013 

 

2012 

 

 

 

 

 

 

 

 

 

 

 

Operating Activities:

 

 

 

 

 

 

 

 

 

Net Income

$

 57,819 

 

$

 60,438 

 

$

 54,503 

 

Adjustments to Reconcile Net Income to Net Cash Flows

 

 

 

 

 

 

 

 

 

 

Provided by Operating Activities:

 

 

 

 

 

 

 

 

 

 

 Depreciation

 

 41,886 

 

 

 37,568 

 

 

 29,971 

 

 

 Deferred Income Taxes

 

 34,108 

 

 

 87,028 

 

 

 53,942 

 

 

 Regulatory Overrecoveries, Net

 

 1,925 

 

 

 8,458 

 

 

 (19,152)

 

 

 Amortization of Regulatory (Liabilities)/Assets, Net

 

 (6,228)

 

 

 (3,206)

 

 

 410 

 

 

 Amortization of Rate Reduction Bonds

 

 - 

 

 

 7,780 

 

 

 17,632 

 

 

 Proceeds from DOE Damages Claim

 

 18,883 

 

 

 - 

 

 

 - 

 

 

 Other

 

 (2,005)

 

 

 3,381 

 

 

 (3,954)

 

Changes in Current Assets and Liabilities:

 

 

 

 

 

 

 

 

 

 

 Receivables and Unbilled Revenues, Net

 

 39,872 

 

 

 (53,292)

 

 

 (8,896)

 

 

 Materials and Supplies

 

 (627)

 

 

 865 

 

 

 (2,882)

 

 

 Taxes Receivable/Accrued, Net

 

 (22,454)

 

 

 19,840 

 

 

 (8,311)

 

 

 Accounts Payable

 

 1,269 

 

 

 7,456 

 

 

 (19,297)

 

 

 Other Current Assets and Liabilities, Net

 

 (11,169)

 

 

 2,491 

 

 

 581 

Net Cash Flows Provided by Operating Activities

 

 153,279 

 

 

 178,807 

 

 

 94,547 

 

 

 

 

 

 

 

 

 

 

 

Investing Activities:

 

 

 

 

 

 

 

 

 

Investments in Property, Plant and Equipment

 

 (116,205)

 

 

 (128,786)

 

 

 (264,175)

 

Proceeds from Sales of Marketable Securities

 

 73,198 

 

 

 70,778 

 

 

 79,769 

 

Purchases of Marketable Securities

 

 (73,888)

 

 

 (71,390)

 

 

 (80,529)

 

Decrease in Notes Receivable from Affiliate

 

 - 

 

 

 - 

 

 

 11,000 

 

Other Investing Activities

 

 3,200 

 

 

 7,401 

 

 

 (28)

Net Cash Flows Used in Investing Activities

 

 (113,695)

 

 

 (121,997)

 

 

 (253,963)

 

 

 

 

 

 

 

 

 

 

 

Financing Activities:

 

 

 

 

 

 

 

 

 

Cash Dividends on Common Stock

 

 (59,999)

 

 

 (40,001)

 

 

 (9,432)

 

Issuance of Long-Term Debt

 

 - 

 

 

 80,000 

 

 

 150,000 

 

Retirements of Long-Term Debt

 

 - 

 

 

 (55,000)

 

 

 (53,800)

 

Increase/(Decrease) in Notes Payable to NU Parent

 

 21,400 

 

 

 (31,900)

 

 

 31,900 

 

Retirements of Rate Reduction Bonds

 

 - 

 

 

 (9,352)

 

 

 (17,540)

 

Capital Contributions from NU Parent

 

 - 

 

 

 - 

 

 

 50,000 

 

Other Financing Activities

 

 (985)

 

 

 (558)

 

 

 8,288 

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

 

 (39,584)

 

 

 (56,811)

 

 

 159,416 

Net Decrease in Cash

 

 - 

 

 

 (1)

 

 

 - 

Cash - Beginning of Year

 

 - 

 

 

 1 

 

 

 1 

Cash - End of Year

$

 - 

 

$

 - 

 

$

 1 

 

 

 

 

 

 

 

 

 

 

 

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




91


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 FINANCIAL STATEMENTS


Refer to the Glossary of Terms included in this combined Annual Report on Form 10-K for abbreviations and acronyms used throughout the combined notes to the financial statements.


1.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES


A.

About NU, CL&P, NSTAR Electric, PSNH and WMECO

NU Consolidated:  NU is a public utility holding company primarily engaged through its wholly owned regulated utility subsidiaries in the energy delivery business.  On April 10, 2012, NU acquired NSTAR and its subsidiaries.  See Note 21, "Merger of NU and NSTAR," for further information regarding the merger.  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.  On February 2, 2015, NU, CL&P, NSTAR Electric, PSNH and WMECO commenced doing business as Eversource Energy.


NU, CL&P, NSTAR Electric, PSNH and WMECO are reporting companies under the Securities Exchange Act of 1934.  NU is a public utility holding company under the Public Utility Holding Company Act of 2005.  Arrangements among the regulated electric companies and other NU companies, outside agencies and other utilities covering interconnections, interchange of electric power and sales of utility property are subject to regulation by the FERC.  The Regulated companies are subject to regulation of rates, accounting and other matters by the FERC and/or applicable state regulatory commissions (the PURA for CL&P and Yankee Gas, the DPU for NSTAR Electric, WMECO and NSTAR Gas, and the NHPUC for PSNH).


Regulated Companies:  CL&P, NSTAR Electric, PSNH and WMECO furnish franchised retail electric service in Connecticut, Massachusetts and New Hampshire.  Yankee Gas and NSTAR Gas are engaged in the distribution and sale of natural gas to customers within Connecticut and central and eastern Massachusetts, respectively.  CL&P, NSTAR Electric, PSNH and WMECO's results include the operations of their respective distribution and transmission businesses.  PSNH and WMECO's distribution results include the operations of their respective generation businesses.  NU also has a regulated subsidiary, NPT, which was formed to construct, own and operate the Northern Pass line, a HVDC transmission line from Québec to New Hampshire under development that will interconnect with a new HVDC transmission line being developed by a transmission subsidiary of HQ.  


Other:  NUSCO, NU's service company, Rocky River Realty Company, a wholly-owned real estate subsidiary of NU, Renewable Properties, Inc., a wholly-owned subsidiary of EETV, and Properties, Inc., a wholly-owned subsidiary of PSNH, provide support services to NU, including its regulated companies.  Harbor Electric Energy Company, a wholly-owned subsidiary of NSTAR Electric, provides distribution service and ongoing support to the Massachusetts Water Resources Authority.  Hopkinton LNG Corp, an indirect, wholly-owned subsidiary of NU, provides natural gas liquefaction, vaporization, and storage services for NSTAR Gas.  


B.

Basis of Presentation

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


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.


NU's consolidated financial information includes NSTAR and its subsidiaries' results of operations beginning April 10, 2012.  The information disclosed for the year ended December 31, 2012 for NSTAR Electric is presented on a comparable basis.  


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.  


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' distribution, generation and transmission businesses and NPT are 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 year data were made in the accompanying balance sheets for NU, CL&P, NSTAR Electric and PSNH.  These reclassifications were made to conform to the current year presentation.


In accordance with accounting guidance on noncontrolling interests in consolidated financial statements, the Preferred Stock of CL&P and the Preferred Stock of NSTAR Electric, which are not owned by NU or its consolidated subsidiaries and are not subject to mandatory redemption, have



92


been presented as noncontrolling interests in the financial statements of NU.  The Preferred Stock of CL&P and the Preferred Stock of NSTAR Electric are considered to be temporary equity and have been classified between liabilities and permanent shareholders' equity on the balance sheets of NU, CL&P and NSTAR Electric due to a provision in the preferred stock agreements of both CL&P and NSTAR Electric that grant preferred stockholders the right to elect a majority of the CL&P and NSTAR Electric Board of Directors, respectively, should certain conditions exist, such as if preferred dividends are in arrears for a specified amount of time.  The Net Income reported in the statements of income and cash flows represents net income prior to apportionment to noncontrolling interests, which is represented by dividends on preferred stock of CL&P and NSTAR Electric.


As of December 31, 2014 and 2013, NU's carrying amount of goodwill was approximately $3.5 billion.  NU performs an assessment for possible impairment of its goodwill at least annually.  NU completed its annual goodwill impairment test for each of its reporting units as of October 1, 2014 and determined that no impairment exists.  See Note 22, "Goodwill," for further information.


C.

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 ASU.  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.


D.

Cash and Cash Equivalents

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


E.

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 judgments and factors, including the application of an estimated uncollectible percentage to each receivable aging category.  The estimate is based upon historical collection and write-off experience and management's assessment of collectability from customers.  Management continuously assesses the collectability of receivables and adjusts collectability estimates based on actual experience.  Receivable balances are written off against the provision for uncollectible accounts when the accounts are terminated and these balances are deemed to be uncollectible.  


The PURA allows CL&P and Yankee Gas to accelerate the recovery of accounts receivable balances attributable to qualified customers under financial or medical duress (uncollectible hardship accounts receivable) outstanding for greater than 90 days.  The DPU allows WMECO to also recover in rates amounts associated with certain uncollectible hardship accounts receivable.  Uncollectible customer account balances, which are expected to be recovered in rates, are included in Regulatory Assets or Other Long-Term Assets.  


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


 

 

Total Provision for Uncollectible Accounts

 

Uncollectible Hardship

 

 

As of December 31,

 

As of December 31,

(Millions of Dollars)

2014 

 

2013 

 

2014 

 

2013 

NU

$

175.3 

 

$

171.3 

 

$

91.5 

 

$

81.2 

CL&P

 

84.3 

 

 

82.0 

 

 

74.0 

 

 

67.3 

NSTAR Electric

 

40.7 

 

 

41.7 

 

 

 -   

 

 

 -   

PSNH

 

7.7 

 

 

7.4 

 

 

 -   

 

 

 -   

WMECO

 

9.9 

 

 

10.0 

 

 

6.2 

 

 

5.5 


F.

Fuel, Materials and Supplies and Allowance Inventory

Fuel, Materials and Supplies include natural gas, coal, biomass and oil inventories as well as materials purchased primarily for construction or operation and maintenance purposes.  Natural gas, coal, biomass and oil inventories are valued at their respective weighted average cost.  Materials and supplies are valued at the lower of average cost or market.  As of December 31, 2014, NU and PSNH had $164.3 million and $95.1 million, respectively, of fuel and $185.4 million and $53 million, respectively, of materials and supplies.  As of December 31, 2013, NU and PSNH had $139.5 million and $74.2 million, respectively, of fuel and $163.7 million and $54.5 million, respectively, of materials and supplies.


Fuel, Materials and Supplies also include Renewable Energy Certificates (RECs), which are purchased from suppliers of renewable sources of generation.  RECs are used to meet state mandated Renewable Portfolio Standards requirements.  As of December 31, 2014 and 2013, NSTAR Electric had $25.1 million and $4.9 million, respectively, of RECs classified as Materials and Supplies on the balance sheets.  


PSNH is subject to federal and state laws and regulations that regulate emissions of air pollutants, including SO2, CO2, and NOx related to its regulated generation units, and uses SO2, CO2, and NOx emissions allowances.  At the end of each compliance period, PSNH is required to relinquish SO2, CO2, and NOx emissions allowances corresponding to the actual respective emissions emitted by its generating units over the compliance period.  SO2 and NOx emissions allowances are obtained through an annual allocation from the federal and state regulators that are granted at no cost and through purchases from third parties.  CO2 emissions allowances are obtained through an annual allocation from the state regulator that are



93


granted at no cost and are acquired through auctions and through purchases from third parties.  SO2, CO2, and NOx emissions allowances are charged to expense based on their weighted average cost as they are utilized against emissions volumes at PSNH's generating units.  


SO2, CO2, and NOx emissions allowances are recorded within Fuel, Materials and Supplies and are classified on the balance sheet as short-term or long-term depending on the period in which they are expected to be utilized against actual emissions.  As of December 31, 2014 and 2013, PSNH had $20.1 million and $19.4 million, respectively, of long-term SO2 and CO2 emissions allowances classified as Other Long-Term Assets on the balance sheets.  


G.

Restricted Cash and Other Deposits

As of December 31, 2014, NU, CL&P and PSNH had $3.2 million, $2.1 million, and $1 million, respectively, of restricted cash relating to amounts held in escrow, which were included in Prepayments and Other Current Assets on the balance sheets.  As of December 31, 2013, these amounts were $1.7 million and $1.4 million for NU and CL&P, respectively.


As of December 31, 2014, NU, CL&P and PSNH had $9.9 million, $1.2 million and $2.5 million, respectively, of cash collateral posted not subject to master netting agreements, primarily with ISO-NE, which were included in Prepayments and Other Current Assets on the balance sheets.  As of December 31, 2013, these amounts were $17.9 million and $9 million for NU and NSTAR Electric, respectively.


H.

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 valuations of the investments used to calculate the funded status of pension and PBOP plans and nonrecurring fair value measurements of nonfinancial assets such as goodwill and AROs, 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," Note 6, "Asset Retirement Obligations," Note 9A, "Employee Benefits – Pension Benefits and Postretirement Benefits Other Than Pensions," Note 13, "Fair Value of Financial Instruments," and Note 21, "Merger of NU and NSTAR," to the financial statements.


I.

Derivative Accounting

Many of the Regulated companies' contracts for the purchase and sale of energy or energy-related products are derivatives.  The accounting treatment for energy contracts entered into varies and depends on the intended use of the particular contract and on whether or not the contract is a derivative.  For the Regulated companies, regulatory assets or regulatory liabilities are recorded to offset the fair values of derivative contracts, as contract settlements are recovered from, or refunded to, customers in future rates.


The application of derivative accounting is complex and requires management judgment in the following respects: identification of derivatives and embedded derivatives, election and designation of the normal exception, and determination of the fair value of derivative contracts.  All of these judgments can have a significant impact on the financial statements.  


The judgment applied in the election of the normal exception (and resulting accrual accounting) includes the conclusion that it is probable at the inception of the contract and throughout its term that it will result in physical delivery of the underlying product and that the quantities will be used or sold by the business in the normal course of business.  If facts and circumstances change and management can no longer support this conclusion, then the normal exception and accrual accounting is terminated, and fair value accounting is applied prospectively.  


The fair value of derivative contracts is based upon the contract terms and conditions and the underlying market price or fair value per unit.  When quantities are not specified in the contract, the Company determines whether the contract has a determinable quantity by using amounts referenced in default provisions and other relevant sections of the contract.  The fair value of derivative assets and liabilities with the same counterparty are offset and recorded as a net derivative asset or liability on the balance sheets.  Changes in the fair value of derivative contracts are recorded as regulatory assets or liabilities and do not impact net income.


For further information regarding derivative contracts, see Note 4, "Derivative Instruments," to the financial statements.




94


J.

Equity Method Investments

Regional Decommissioned Nuclear Companies:  CL&P, NSTAR Electric, PSNH and WMECO own common stock in three regional nuclear generation companies (CYAPC, YAEC and MYAPC, collectively referred to as the Yankee Companies), each of which owned a single nuclear generating facility that has been decommissioned.  For CL&P, NSTAR Electric, PSNH and WMECO, the respective investments in CYAPC, YAEC and MYAPC are accounted for under the equity method.  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.


Ownership interests in the Yankee Companies as of December 31, 2014 and 2013 were as follows:


(Percent)

CYAPC

 

YAEC

 

MYAPC

CL&P

 34.5 

%

 

 24.5 

%

 

 12.0 

%

NSTAR Electric

 14.0 

 

 

 14.0 

 

 

 4.0 

 

PSNH

 5.0 

 

 

 7.0 

 

 

 5.0 

 

WMECO

 9.5 

 

 

 7.0 

 

 

 3.0 

 


The total carrying values of CL&P's, NSTAR Electric's, PSNH's and WMECO's ownership interests in CYAPC, YAEC and MYAPC, which are included in Other Long-Term Assets on their respective balance sheets, were as follows:  


 

As of December 31,

(Millions of Dollars)

2014 

 

2013 

CL&P

$

 1.2 

 

$

 1.2 

NSTAR Electric

 

 0.5 

 

 

 0.5 

PSNH

 

 0.3 

 

 

 0.3 

WMECO

 

 0.3 

 

 

 0.3 


For further information on the Yankee Companies, see Note 11C, "Commitments and Contingencies - Contractual Obligations - Yankee Companies," to the financial statements.


Other Investments:  As of December 31, 2014 and 2013, NU had an equity ownership interest in an energy investment fund of $17.8 million and $9.8 million, respectively.  


Equity investments are included in Other Long-Term Assets on the balance sheets and net earnings related to these equity investments are included in Other Income, Net on the statements of income.  


K.

Revenues

Regulated Companies:  The Regulated companies' retail revenues are based on rates approved by their respective state regulatory commissions.  In general, rates can only be changed through formal proceedings with the state regulatory commissions.  The Regulated companies' rates are designed to recover the costs to provide service to their customers, including a return on investment.  The Regulated companies also utilize regulatory commission-approved tracking mechanisms to recover certain costs on a fully-reconciling basis.  These tracking mechanisms require rates to be changed periodically to ensure recovery of actual costs incurred.  WMECO and CL&P (effective December 1, 2014), each have a revenue decoupling mechanism to recover a pre-established level of baseline distribution delivery service revenues per year, independent of actual customer usage.  Decoupling mechanisms effectively break the relationship between sales volumes and revenues recognized.


A significant portion of the Regulated companies' retail revenues relate to the recovery of costs incurred for the sale of electricity and natural gas purchased on behalf of customers.  These energy supply costs are recovered from customers in rates through cost tracking mechanisms.  Energy purchases are recorded in Purchased Power, Fuel and Transmission, and the sale of energy associated with these purchases are recorded in Operating Revenues.


Regulated Companies' Unbilled Revenues:  Because customers are billed throughout the month based on pre-determined cycles rather than on a calendar month basis, an estimate of electricity or natural gas delivered to customers for which the customers have not yet been billed is calculated as of the balance sheet date.  Unbilled revenues are included in Operating Revenues on the statements of income and are assets on the balance sheets.  Actual amounts billed to customers when meter readings become available may vary from the estimated amount.


The Regulated companies estimate unbilled sales monthly using the daily load cycle method.  The daily load cycle method allocates billed sales to the current calendar month based on the daily load for each billing cycle.  The billed sales are subtracted from total month load, net of delivery losses, to estimate unbilled sales.  Unbilled revenues are estimated by first allocating unbilled sales to the respective customer classes, then applying an estimated rate by customer class to those sales.  


Regulated Companies' Transmission Revenues - Wholesale Rates:  Wholesale transmission revenues are recovered through FERC approved formula rates.  Wholesale transmission revenues for CL&P, NSTAR Electric, PSNH, and WMECO are collected under the ISO New England Inc. Transmission, Markets and Services Tariff (ISO-NE Tariff).  The ISO-NE Tariff includes Regional Network Service (RNS), Schedule 21 - NU rate schedules, which recover the costs of transmission and other transmission-related services for CL&P, PSNH and WMECO, and Schedule 21 - NSTAR rate schedules, which recover costs of transmission and other transmission-related services for NSTAR Electric.  The RNS rate, administered by ISO-NE and billed to all New England transmission load, including CL&P, NSTAR Electric, PSNH and WMECO's distribution businesses, is reset on June 1st of each year and recovers the revenue requirements associated with transmission facilities that benefit the entire New England region.  Schedule 21 - NU and Schedule 21 - NSTAR rates, administered by NU, recovers the remainder of the transmission revenue requirements.  The Schedule 21 - NU rate is reset on January 1st and June 1st of each year, while the Schedule 21 - NSTAR rate is reset on June 1st of each year.  The Schedule 21 - NU and Schedule 21 - NSTAR rate calculations recover total transmission revenue requirements net of revenues



95


received from other sources (i.e., RNS, rentals, etc.), thereby ensuring that NU recovers all of CL&P's, NSTAR Electric's, PSNH's and WMECO's regional and local transmission revenue requirements in accordance with the ISO-NE Tariff.  RNS, Schedule 21 - NU and Schedule 21 - NSTAR rates provide for the annual reconciliation and recovery or refund of estimated costs to actual costs.  The financial impacts of differences between actual and estimated costs are deferred for future recovery from, or refunded to, transmission customers.  See Note 11E, "Commitments and Contingencies – FERC Base ROE Complaints," for complaints filed at FERC relating to NU's base ROE.


Regulated Companies' Transmission Revenues - Retail Rates:  A significant portion of the NU transmission segment revenue comes from ISO-NE charges to the distribution businesses of CL&P, NSTAR Electric, PSNH and WMECO, each of which recovers these costs through rates charged to their retail customers.  CL&P, NSTAR Electric, PSNH and WMECO each have a retail transmission cost tracking mechanism as part of their rates, which allows the electric distribution companies to charge their retail customers for transmission costs on a timely basis.


L.

Operating Expenses

Costs related to fuel and natural gas included in Purchased Power, Fuel and Transmission on the statements of income were as follows:


 

For the Years Ended December 31,

 

 

(Millions of Dollars)

2014 

 

2013 

 

2012 

 

 

NU - Natural Gas and Fuel (1)

$

 599.4 

 

$

 466.5 

 

$

 346.8 

 

 

PSNH – Fuel

 

 113.4 

 

 

 104.8 

 

 

 103.4 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1) NSTAR Gas natural gas costs were included in NU beginning April 10, 2012.


M.

Allowance for Funds Used During Construction

AFUDC represents the cost of borrowed and equity funds used to finance construction and is included in the cost of the Regulated companies' utility plant.  The portion of AFUDC attributable to borrowed funds is recorded as a reduction of Other Interest Expense, and the AFUDC related to equity funds is recorded as Other Income, Net on the statements of income.  AFUDC costs are recovered from customers over the service life of the related plant in the form of increased revenue collected as a result of higher depreciation expense.


The Regulated companies' average AFUDC rate is based on a FERC-prescribed formula using the cost of a company's short-term financings and capitalization (preferred stock, long-term debt and common equity), as appropriate.  The average rate is applied to average eligible CWIP amounts to calculate AFUDC.


NU

For the Years Ended December 31,

(Millions of Dollars, except percentages)

2014

 

2013 

 

2012 (1)

Borrowed Funds

$

5.8 

 

$

4.1 

 

$

5.3 

Equity Funds

 

13.7 

 

 

7.1 

 

 

6.8 

Total AFUDC

$

19.5 

 

$

11.2 

 

$

12.1 

Average AFUDC Rate

 

3.4%

 

 

2.7%

 

 

3.7%

 

 

 

 

 

 

 

 

 

 

(1) NSTAR amounts were included in NU beginning April 10, 2012.

 


 

 

For the Years Ended December 31,

 

 

2014 

 

2013 

 

2012 

(Millions of Dollars,

 

 

 

NSTAR

 

 

 

 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

 except percentages)

CL&P

 

Electric

 

PSNH

 

WMECO

 

CL&P

 

Electric

 

PSNH

 

WMECO

 

CL&P

 

Electric

 

PSNH

 

WMECO

Borrowed Funds

$

 1.9 

 

$

 2.0 

 

$

 0.6 

 

$

 0.9 

 

$

 2.2 

 

$

 0.5 

 

$

 0.5 

 

$

 0.5 

 

$

 2.5 

 

$

 0.3 

 

$

 1.6 

 

$

 0.5 

Equity Funds

 

 2.9 

 

 

 3.8 

 

 

 0.6 

 

 

 1.7 

 

 

 2.9 

 

 

 -  

 

 

 0.2 

 

 

 1.0 

 

 

 1.9 

 

 

 -  

 

 

 1.9 

 

 

 1.0 

Total AFUDC

$

 4.8 

 

$

 5.8 

 

$

 1.2 

 

$

 2.6 

 

$

 5.1 

 

$

 0.5 

 

$

 0.7 

 

$

 1.5 

 

$

 4.4 

 

$

 0.3 

 

$

 3.5 

 

$

 1.5 

Average AFUDC Rate

 

3.4%

 

 

2.5%

 

 

1.8%

 

 

5.6%

 

 

3.7%

 

 

0.5%

 

 

1.1%

 

 

6.1%

 

 

3.6%

 

 

0.4%

 

 

5.9%

 

 

6.8%


N.

Other Income, Net

Items included within Other Income, Net on the statements of income primarily consist of investment income/(loss), interest income, AFUDC related to equity funds, and equity in earnings.  Investment income/(loss) primarily relates to debt and equity securities held in trust.  For further information, see Note 5, "Marketable Securities," to the financial statements.  For further information on AFUDC related to equity funds, see Note 1M, "Summary of Significant Accounting Policies – Allowance for Funds Used During Construction," to the financial statements.  


O.

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 Years Ended December 31,

(Millions of Dollars)

2014 

 

2013 

 

2012 

NU

$

 148.2 

 

$

 144.1 

 

$

 135.0 

CL&P

 

 127.9 

 

 

 128.2 

 

 

 120.7 


Certain sales taxes are 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.   




96



P.

Supplemental Cash Flow Information

 

 

 

 

 

 

 

 

 

 

 

 

NU

As of and For the Years Ended December 31,

(Millions of Dollars)

2014 

 

2013 

 

2012 (1)

Cash Paid/(Received) During the Year for:

 

 

 

 

 

 

 

 

 

Interest, Net of Amounts Capitalized

$

 349.6 

 

$

343.3 

 

$

 356.5 

 

Income Taxes

 

 334.2 

 

 

 50.0 

 

 

 (12.8)

Non-Cash Investing Activities:

 

 

 

 

 

 

 

 

 

Plant Additions Included in Accounts Payable (As of)

 

 181.9 

 

 

193.1 

 

 

160.6 

 

 

 

 

 

 

 

 

 

 

 

 

(1) NSTAR amounts were included in NU beginning April 10, 2012.


 

 

As of and For the Years Ended December 31,

 

 

2014 

 

2013 

 

2012 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

(Millions of Dollars)

CL&P

 

Electric

 

PSNH

 

WMECO

 

CL&P

 

Electric

 

PSNH

 

WMECO

 

CL&P

 

Electric

 

PSNH

 

WMECO

Cash Paid/(Received) During the Year for:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest, Net of Amounts Capitalized

$

144.1 

 

$

75.3 

 

$

41.1 

 

$

25.9 

 

$

131.6 

 

$

75.8 

 

$

43.3 

 

$

25.8 

 

$

 129.4 

 

$

94.6 

 

$

 49.8 

 

$

 25.8 

 

Income Taxes

 

135.4 

 

 

217.1 

 

 

2.3 

 

 

25.1 

 

 

55.0 

 

 

163.4 

 

 

(30.1)

 

 

(69.0)

 

 

 (42.0)

 

 

88.1 

 

 

 14.7 

 

 

 (8.4)

Non-Cash Investing Activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Plant Additions Included in

   Accounts Payable (As of)

 

63.5 

 

 

34.6 

 

 

39.3 

 

 

14.2 

 

 

51.4 

 

 

57.0 

 

 

34.9 

 

 

19.5 

 

 

 42.8 

 

 

50.0 

 

 

 16.8 

 

 

 30.0 


In 2014, as a result of damages awarded to the Yankee Companies for spent nuclear fuel lawsuits against the DOE described in Note 11C, "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.  


The merger of NU with NSTAR on April 10, 2012 represented a significant non-cash transaction.  Refer to Note 21, "Merger of NU and NSTAR," for further information.


Q.

Related Parties

NUSCO, NU's service company, provides centralized accounting, administrative, engineering, financial, information technology, legal, operational, planning, purchasing, and other services to NU's companies.  The Rocky River Realty Company, Renewable Properties, Inc. and Properties, Inc., three other NU subsidiaries, construct, acquire or lease some of the property and facilities used by NU's companies.


As of both December 31, 2014 and 2013, CL&P, PSNH and WMECO had long-term receivables from NUSCO in the amounts of $25 million, $3.8 million and $5.5 million, respectively, which were included in Other Long-Term Assets on the balance sheets.  These amounts related to the funding of investments held in trust by NUSCO in connection with certain postretirement benefits for CL&P, PSNH and WMECO employees and have been eliminated in consolidation on the NU financial statements.


Included in the CL&P, NSTAR Electric, PSNH and WMECO balance sheets as of December 31, 2014 and 2013 were Accounts Receivable from Affiliated Companies and Accounts Payable to Affiliated Companies relating to transactions between CL&P, NSTAR Electric, PSNH and WMECO and other subsidiaries that are wholly-owned by NU.  These amounts have been eliminated in consolidation on the NU financial statements.


R.

Severance Benefits

For the years ended December 31, 2014 and 2013, NU recorded severance benefit expenses of $15 million and $9.7 million, respectively, in connection with the partial outsourcing of information technology functions and facilities closures, as well as ongoing post-merger integration.  As of December 31, 2014 and 2013, the severance accrual totaled $10.4 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.




97


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


NU

As of December 31,

(Millions of Dollars)

2014 

 

2013 

Benefit Costs

$

 2,016.0 

 

$

 1,240.2 

Derivative Liabilities

 

 425.5 

 

 

 638.0 

Income Taxes, Net

 

 635.3 

 

 

 626.2 

Storm Restoration Costs

 

 502.8 

 

 

 589.6 

Goodwill-related

 

 505.4 

 

 

 525.9 

Regulatory Tracker Mechanisms

 

 350.5 

 

 

 323.4 

Contractual Obligations - Yankee Companies

 

 123.8 

 

 

 154.2 

Buy Out Agreements for Power Contracts

 

 42.6 

 

 

 70.2 

Other Regulatory Assets

 

 124.7 

 

 

 126.8 

Total Regulatory Assets

 

 4,726.6 

 

 

 4,294.5 

Less:  Current Portion

 

 672.5 

 

 

 535.8 

Total Long-Term Regulatory Assets

$

 4,054.1 

 

$

 3,758.7 


 

 

As of December 31,

 

 

2014 

 

2013 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

(Millions of Dollars)

CL&P

 

Electric

 

PSNH

 

WMECO

 

CL&P

 

Electric

 

PSNH

 

WMECO

Benefit Costs

$

 445.4 

 

$

 515.9 

 

$

 174.3 

 

$

 85.0 

 

$

 297.7 

 

$

 496.7 

 

$

 100.6 

 

$

 57.3 

Derivative Liabilities

 

 410.9 

 

 

 4.5 

 

 

 - 

 

 

 - 

 

 

 630.4 

 

 

 7.7 

 

 

 - 

 

 

 - 

Income Taxes, Net

 

 437.7 

 

 

 83.7 

 

 

 38.0 

 

 

 35.5 

 

 

 415.5 

 

 

 84.0 

 

 

 40.3 

 

 

 43.7 

Storm Restoration Costs

 

 319.6 

 

 

 103.7 

 

 

 47.7 

 

 

 31.8 

 

 

 397.8 

 

 

 109.3 

 

 

 43.7 

 

 

 38.8 

Goodwill-related

 

 - 

 

 

 433.9 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 451.5 

 

 

 - 

 

 

 - 

Regulatory Tracker Mechanisms

 

 16.1 

 

 

 141.4 

 

 

 103.5 

 

 

 33.0 

 

 

 8.0 

 

 

 169.5 

 

 

 83.3 

 

 

 32.6 

Buy Out Agreements for Power Contracts

 

 - 

 

 

 38.6 

 

 

 4.0 

 

 

 - 

 

 

 - 

 

 

 64.7 

 

 

 5.5 

 

 

 - 

Other Regulatory Assets

 

 66.1 

 

 

 56.1 

 

 

 37.3 

 

 

 12.9 

 

 

 64.6 

 

 

 55.9 

 

 

 38.1 

 

 

 16.7 

Total Regulatory Assets

 

 1,695.8 

 

 

 1,377.8 

 

 

 404.8 

 

 

 198.2 

 

 

 1,814.0 

 

 

 1,439.3 

 

 

 311.5 

 

 

 189.1 

Less:  Current Portion

 

 220.3 

 

 

 198.7 

 

 

 111.7 

 

 

 51.9 

 

 

 150.9 

 

 

 204.1 

 

 

 92.2 

 

 

 43.0 

Total Long-Term Regulatory Assets

$

 1,475.5 

 

$

 1,179.1 

 

$

 293.1 

 

$

 146.3 

 

$

 1,663.1 

 

$

 1,235.2 

 

$

 219.3 

 

$

 146.1 


Regulatory Costs in Other Long-Term Assets:  The Regulated companies had $60.5 million ($1.3 million for CL&P, $33.2 million for NSTAR Electric, $0.9 million for PSNH, and $11 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 December 31, 2014 and 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.  The NSTAR Electric balance as of December 31, 2014 and 2013 primarily related to costs deferred in connection with the basic service bad debt adder.  See Note 11G, "Commitments and Contingencies – Basic Service Bad Debt Adder," for further information.


Equity Return on Regulatory Assets:  For rate-making purposes, the Regulated companies recover the carrying costs related to their regulatory assets.  For certain regulatory assets, the carrying cost recovered includes an equity return component.  This equity return, which is not recorded on the balance sheets, totaled $1.7 million and $1.9 million for CL&P and $43.3 million and $33.1 million for PSNH as of December 31, 2014 and 2013, respectively.  These carrying costs will be recovered from customers in future rates.  


Regulatory Assets - The following provides further information about regulatory assets:


Benefit Costs:  NU's Pension, SERP and PBOP Plans are accounted for in accordance with accounting guidance on defined benefit pension and other PBOP plans.  The liability recorded by the Regulated companies to recognize the funded status of their retiree benefit plans are offset by regulatory assets in lieu of a charge to Accumulated Other Comprehensive Income/(Loss), reflecting ultimate recovery from customers through rates.  All amounts are remeasured annually.  Regulatory accounting was also applied to the portions of NU's service company costs that support the Regulated companies, as these amounts are also recoverable.  As these regulatory assets do not represent a cash outlay for the Regulated companies, no carrying charge is recovered from customers.


The increase in the funded status liability of the retiree benefit plans and the corresponding regulatory assets was primarily driven by a change in mortality assumptions, which increased the estimate of benefits to be provided to plan participants, and a decrease in the discount rate assumption.  For further information on the funded status liability and related regulatory assets of the Pension, SERP and PBOP plans, see Note 9A, "Employee Benefits – Pension Benefits and Postretirement Benefits Other Than Pensions."


CL&P, NSTAR Electric, PSNH and WMECO recover benefit costs related to their distribution and transmission operations from customers in rates as allowed by their applicable regulatory commissions.  NSTAR Electric and WMECO each recover their qualified pension and PBOP expenses related to distribution operations through rate reconciling mechanisms that fully track the change in net pension and PBOP expenses each year.  


Derivative Liabilities:  Regulatory assets recorded as an offset to derivative liabilities relate to the fair value of contracts used to purchase energy and energy-related products that will be recovered from customers in future rates.  See Note 4, "Derivative Instruments," to the financial statements for further information.  These assets are excluded from rate base and are being recovered as the actual settlements occur over the duration of the contracts.




98


Income Taxes, Net:  The tax effect of temporary book-tax differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income, including those differences relating to uncertain tax positions) is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and accounting guidance for income taxes.  Differences in income taxes between the accounting guidance and the rate-making treatment of the applicable regulatory commissions are recorded as regulatory assets.  As these assets are offset by deferred income tax liabilities, no carrying charge is collected. For further information regarding income taxes, see Note 10, "Income Taxes," to the financial statements.  


Storm Restoration Costs:  The storm restoration cost deferrals relate to costs incurred at CL&P, NSTAR Electric, PSNH and WMECO that each company expects to recover from customers.  A storm must meet certain criteria to be declared a major storm with the criteria specific to each state jurisdiction and utility company.  Once a storm is declared major, all qualifying expenses incurred during storm restoration efforts are deferred and recovered from customers.  In addition to storm restoration costs, CL&P and PSNH are each allowed to recover storm pre-staging costs in accordance with applicable regulation.


CL&P, NSTAR Electric, PSNH and WMECO experienced several significant storm events, including Tropical Storm Irene in 2011, the October 2011 snowstorm, Storm Sandy in 2012 and the February 2013 blizzard.  As a result of these storm events, each company suffered extensive damage to its distribution and transmission systems resulting in customer outages.  Each company incurred significant costs to repair damage and restore customers' service.  In addition, on November 26, 2014, a snowstorm caused damage to the electric delivery systems of PSNH and WMECO.  This snowstorm resulted in estimated deferred storm restoration costs of approximately $23 million at PSNH and approximately $3 million at WMECO.  The storm restoration cost regulatory asset balance at CL&P, NSTAR Electric, PSNH and WMECO reflects deferrable costs incurred for major storm events.  Management believes the storm restoration costs were prudent and meet the criteria for specific cost recovery in Connecticut, Massachusetts and New Hampshire, and that recovery from customers is probable through the applicable regulatory recovery process.


Storm Filings:  Each electric utility has sought, or is seeking, recovery of its deferred storm restoration costs through its applicable regulatory recovery process.  


CL&P:  As of December 31, 2014, all CL&P deferred storm costs have been reviewed and approved for recovery in distribution rates.

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 and ordered CL&P to capitalize approximately $18 million of the deferred storm restoration costs as utility plant, which will be recovered through depreciation expense in future rate proceedings.  CL&P will recover the $365 million in its distribution rates over a six-year period that commenced on December 1, 2014.  The remaining costs were either disallowed or are probable of recovery from other sources.  These costs did not have a material impact on CL&P's financial position, results of operations or cash flows.


Effective June 1, 2014, CL&P received $65.4 million of DOE Phase II Damages proceeds.  On June 17, 2014, the PURA ordered CL&P to refund these proceeds to customers by offsetting the deferred storm restoration costs regulatory asset.  For further information on the DOE Phase II Damages proceeds received from the Yankee Companies, see Note 11C, "Commitments and Contingencies - Contractual Obligations - Yankee Companies," to the financial statements.


On December 17, 2014, as part of the distribution rate case decision, CL&P was also allowed recovery of the 2013 storm costs and residual 2012 Storm Sandy costs over a seven-year period that commenced on December 1, 2014.  


NSTAR Electric:  On December 30, 2013, the DPU approved recovery of $34.2 million of NSTAR Electric's storm restoration costs, plus carrying costs, related to Tropical Storm Irene in 2011 and the October 2011 snowstorm.  NSTAR Electric is recovering these costs, plus carrying costs, in its distribution rates over a five-year period that commenced on January 1, 2014.  


PSNH:  On June 27, 2013, the NHPUC approved an increase to PSNH's distribution rates effective July 1, 2013, which included a $5 million increase to the level of funding for the major storm cost reserve.  The major storm cost reserve is used to offset the storm restoration cost regulatory asset.  On April 7, 2014, PSNH received an audit report from the NHPUC approving storm costs from 2011 through March 2013.


WMECO:  On December 20, 2013, the DPU approved WMECO's 2013 Annual Storm Reserve Recovery Cost Adjustment filing to begin recovering the October 2011 snowstorm and 2012 Storm Sandy restoration costs, which commenced on January 1, 2014, subject to further review and reconciliation.  On December 5, 2014, the DPU approved the majority of deferred storm costs through 2011.


Goodwill-related:  The goodwill regulatory asset originated from the transaction that created NSTAR in 1999.  This regulatory asset is currently being amortized and recovered from customers in rates without a carrying charge over a 40-year period (as of December 31, 2014, there were 25 years of amortization remaining).


Regulatory Tracker Mechanisms:  The Regulated companies' approved rates are designed to recover their incurred costs to provide service to customers.  The Regulated companies recover certain of their costs on a fully-reconciling basis through regulatory commission-approved tracking mechanisms.  The difference between the costs incurred (or the rate recovery allowed) and the actual revenues is recorded as regulatory assets (for undercollections) or regulatory liabilities (for overcollections) to be included in future customer rates each year.  Carrying charges are recorded on all material regulatory tracker mechanisms.


CL&P, NSTAR Electric, PSNH and WMECO each recover the costs associated with the procurement of energy, transmission related costs from FERC-approved transmission tariffs, energy efficiency programs, low income assistance programs, and restructuring and stranded costs as a result of deregulation, on a fully reconciling basis.  Energy procurement costs at PSNH include the costs related to its generating stations.  


WMECO's and CL&P's (effective December 1, 2014) distribution revenue is decoupled from their customer sales volume.  CL&P and WMECO reconcile their annual base distribution rate recovery to a pre-established level of baseline distribution delivery service revenue.  Any difference



99


between the allowed level of distribution revenue and the actual amount incurred during a 12-month period is adjusted through rates in the following period.


Contractual Obligations - Yankee Companies:  CL&P, NSTAR Electric, PSNH and WMECO are responsible for their proportionate share of the remaining costs of the CYAPC, YAEC and MYAPC nuclear facilities, including nuclear fuel storage.  A portion of these amounts was recorded as a regulatory asset.  Amounts for CL&P are earning a return and are being recovered through the CTA.  Amounts for NSTAR Electric and WMECO are being recovered without a return through the transition charge.  Amounts for PSNH were fully recovered in 2006.  As a result of NU's consolidation of CYAPC and YAEC, NU's regulatory asset balance also includes the regulatory assets of CYAPC and YAEC, which totaled $97.8 million and $129.8 million as of December 31, 2014 and 2013, respectively.  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.


Buy Out Agreements for Power Contracts:  NSTAR Electric's balance represents the contract termination liability related to certain purchase power contract buy out agreements that were executed in 2004.  The contracts' termination payments occur through September 2016 and are collected from customers through NSTAR Electric's transition charge over the same period.  NSTAR Electric does not earn a return on this regulatory asset.  PSNH's balance represents payments associated with the termination of various power purchase contracts that were recorded as regulatory assets and are amortized over the remaining life of the contracts.


Other Regulatory Assets:  Other Regulatory Assets primarily include asset retirement obligations, environmental remediation costs, losses associated with the reacquisition or redemption of long-term debt and various other items, partially offset by purchase price adjustments recorded as Regulatory Assets in connection with the merger with NSTAR.   


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


NU

As of December 31,

(Millions of Dollars)

2014 

 

2013 

Cost of Removal

$

 439.9 

 

$

 435.1 

Regulatory Tracker Mechanisms

 

 192.3 

 

 

 151.2 

AFUDC - Transmission

 

 67.1 

 

 

 68.1 

Other Regulatory Liabilities

 

 50.8 

 

 

 52.9 

Total Regulatory Liabilities

 

 750.1 

 

 

 707.3 

Less:  Current Portion

 

 235.0 

 

 

 204.3 

Total Long-Term Regulatory Liabilities

$

 515.1 

 

$

 503.0 


 

 

As of December 31,

 

 

2014 

 

2013 

 

 

 

 

NSTAR

 

 

 

 

 

 

 

NSTAR

 

 

 

 

(Millions of Dollars)

CL&P

 

Electric

 

PSNH

 

WMECO

 

CL&P

 

Electric

 

PSNH

 

WMECO

Cost of Removal

$

 19.7 

 

$

 258.3 

 

$

 50.3 

 

$

 1.1 

 

$

 29.1 

 

$

 250.0 

 

$

 49.7 

 

$

 - 

Regulatory Tracker Mechanisms

 

 122.6 

 

 

 20.7 

 

 

 14.2 

 

 

 22.3 

 

 

 95.6 

 

 

 21.9 

 

 

 21.6 

 

 

 21.1 

AFUDC – Transmission

 

 53.6 

 

 

 4.4 

 

 

 - 

 

 

 9.1 

 

 

 54.7 

 

 

 4.1 

 

 

 - 

 

 

 9.3 

Other Regulatory Liabilities

 

 10.1 

 

 

 28.9 

 

 

 2.9 

 

 

 0.8 

 

 

 8.4 

 

 

 31.1 

 

 

 1.0 

 

 

 3.4 

Total Regulatory Liabilities

 

 206.0 

 

 

 312.3 

 

 

 67.4 

 

 

 33.3 

 

 

 187.8 

 

 

 307.1 

 

 

 72.3 

 

 

 33.8 

Less:  Current Portion

 

 124.7 

 

 

 49.6 

 

 

 16.0 

 

 

 22.5 

 

 

 94.0 

 

 

 54.0 

 

 

 20.6 

 

 

 19.9 

Total Long-Term Regulatory Liabilities

$

 81.3 

 

$

 262.7 

 

$

 51.4 

 

$

 10.8 

 

$

 93.8 

 

$

 253.1 

 

$

 51.7 

 

$

 13.9 


Cost of Removal:  NU's Regulated companies currently recover amounts in rates for future costs of removal of plant assets over the lives of the assets.  The estimated cost to remove utility assets from service is recognized as a component of depreciation expense and the cumulative amounts collected from customers but not yet expended is recognized as a regulatory liability.  Expended costs that exceed amounts collected from customers are recognized as regulatory assets, as they are probable of recovery in future rates.


AFUDC - Transmission:  AFUDC was recorded by CL&P and WMECO for their NEEWS projects through May 31, 2011, all of which was reserved as a regulatory liability to reflect rate base recovery for 100 percent of the CWIP as a result of FERC-approved transmission incentives.  Effective June 1, 2011, FERC approved changes to the ISO-NE Tariff in order to include 100 percent of the NEEWS CWIP in regional rate base.  As a result, CL&P and WMECO no longer record AFUDC on NEEWS CWIP.  NSTAR Electric recorded AFUDC on reliability-related projects over $5 million through December 31, 2014, 50 percent of which was recorded as a regulatory liability to reflect rate base recovery for 50 percent of the CWIP as a result of FERC-approved transmission incentives.


Other Regulatory Liabilities:  Other Regulatory Liabilities primarily includes amounts that are subject to various rate reconciling mechanisms that, as of each period end date, would result in refunds to customers.


2014 Regulatory Developments:  As a result of actions taken by the FERC and other developments in the pending base ROE complaint proceedings described in Note 11E, "Commitments and Contingencies – FERC Base ROE Complaints," in 2014 the Company recorded reserves at its electric subsidiaries to recognize the potential financial impact of the first and second complaints.  As of December 31, 2014, the cumulative pre-tax reserves (excluding interest), which exclude refunds for the first complaint refund period, totaled $60.7 million at NU, $33.5 million at CL&P, $13.6 million at NSTAR Electric, $5.1 million at PSNH and $8.5 million at WMECO.  As of December 31, 2013, as a result of the 2013 FERC ALJ initial decision, 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 as a regulatory liability in Regulatory Tracker Mechanisms and as a reduction of Operating Revenues.  




100


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 11C, "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 Regulatory Tracker Mechanisms.  Refunds to customers for these DOE proceeds began in 2014.


On December 31, 2014, NSTAR Electric, NSTAR Gas and the Massachusetts Attorney General filed a comprehensive settlement agreement with the DPU.  The comprehensive settlement agreement included resolution of the outstanding NSTAR Electric CPSL program filings for the periods 2006 through 2011, the NSTAR Electric and NSTAR Gas PAM and energy efficiency-related customer billing adjustments reported in 2012, and the NSTAR Electric energy efficiency program filings regarding LBR for the periods 2008 through 2011.  If approved by the DPU, NSTAR Electric and NSTAR Gas will be required to refund a total of $44.7 million to their respective customers, which was included in Regulatory Tracker Mechanisms and Other Regulatory Liabilities as of December 31, 2014.  For further information, see Note 11F, "Commitments and Contingencies – 2014 Comprehensive Settlement Agreement."


3.

PROPERTY, PLANT AND EQUIPMENT AND ACCUMULATED DEPRECIATION


Utility property, plant and equipment is recorded at original cost.  Original cost includes materials, labor, construction overhead and AFUDC for regulated property.  The cost of repairs and maintenance, including planned major maintenance activities, is charged to Operating Expenses as incurred.  


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


NU

As of December 31,

(Millions of Dollars)

2014 

 

2013 

Distribution - Electric

$

 12,495.2 

 

$

 11,950.2 

Distribution - Natural Gas

 

 2,595.4 

 

 

 2,425.9 

Transmission

 

 6,930.7 

 

 

 6,412.5 

Generation

 

 1,170.9 

 

 

 1,152.3 

Electric and Natural Gas Utility

 

 23,192.2 

 

 

 21,940.9 

Other (1)

 

 551.3 

 

 

 508.7 

Property, Plant and Equipment, Gross

 

 23,743.5 

 

 

 22,449.6 

Less:  Accumulated Depreciation

 

 

 

 

 

 

Electric and Natural Gas Utility    

 

 (5,777.8)

 

 

 (5,387.0)

 

Other

 

 (231.8)

 

 

 (196.2)

Total Accumulated Depreciation

 

 (6,009.6)

 

 

 (5,583.2)

Property, Plant and Equipment, Net

 

 17,733.9 

 

 

 16,866.4 

Construction Work in Progress

 

 913.1 

 

 

 709.8 

Total Property, Plant and Equipment, Net

$

 18,647.0 

 

$

 17,576.2 


(1)

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


 

As of December 31,

 

2014 

 

2013 

 

 

 

 

NSTAR

 

 

 

 

 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

(Millions of Dollars)

CL&P

 

Electric

 

PSNH

 

WMECO

 

CL&P

 

Electric

 

PSNH

 

WMECO

Distribution

$

 5,158.8 

 

$

 4,895.5 

 

$

 1,696.7 

 

$

 784.2 

 

$

 4,930.7 

 

$

 4,694.7 

 

$

 1,608.2 

 

$

 756.6 

Transmission

 

 3,274.0 

 

 

 1,928.5 

 

 

 789.7 

 

 

 891.0 

 

 

 3,071.9 

 

 

 1,772.3 

 

 

 695.7 

 

 

 826.4 

Generation

 

 - 

 

 

 - 

 

 

 1,136.5 

 

 

 34.4 

 

 

 - 

 

 

 - 

 

 

 1,131.2 

 

 

 21.1 

Property, Plant and

  Equipment, Gross

 

 8,432.8 

 

 

 6,824.0 

 

 

 3,622.9 

 

 

 1,709.6 

 

 

 8,002.6 

 

 

 6,467.0 

 

 

 3,435.1 

 

 

 1,604.1 

Less:  Accumulated Depreciation

 

 (1,928.0)

 

 

 (1,761.4)

 

 

 (1,090.0)

 

 

 (297.4)

 

 

 (1,804.1)

 

 

 (1,631.3)

 

 

 (1,021.8)

 

 

 (271.5)

Property, Plant and Equipment, Net

 

 6,504.8 

 

 

 5,062.6 

 

 

 2,532.9 

 

 

 1,412.2 

 

 

 6,198.5 

 

 

 4,835.7 

 

 

 2,413.3 

 

 

 1,332.6 

Construction Work in Progress

 

 304.9 

 

 

 272.8 

 

 

 102.9 

 

 

 49.1 

 

 

 252.8 

 

 

 208.2 

 

 

 54.3 

 

 

 48.5 

Total Property, Plant and

  Equipment, Net

$

 6,809.7 

 

$

 5,335.4 

 

$

 2,635.8 

 

$

 1,461.3 

 

$

 6,451.3 

 

$

 5,043.9 

 

$

 2,467.6 

 

$

 1,381.1 


Depreciation of utility assets is calculated on a straight-line basis using composite rates based on the estimated remaining useful lives of the various classes of property (estimated useful life for PSNH distribution).  The composite rates are subject to approval by the appropriate state regulatory agency.  The composite rates include a cost of removal component, which is collected from customers over the lives of the plant assets and is recognized as a regulatory liability.  Depreciation rates are applied to property from the time it is placed in service.


Upon retirement from service, the cost of the utility asset is charged to the accumulated provision for depreciation.  The actual incurred removal costs are applied against the related regulatory liability.  




101


The depreciation rates for the various classes of utility property, plant and equipment aggregate to composite rates as follows:


(Percent)

 

2014 

 

 

2013 

 

 

2012 

 

NU

 

 3.0 

%

 

 2.8 

%

 

 2.5 

%

CL&P

 

 2.7 

 

 

 2.5 

 

 

 2.5 

 

NSTAR Electric

 

 3.0 

 

 

 2.9 

 

 

 2.8 

 

PSNH

 

 3.0 

 

 

 3.0 

 

 

 3.0 

 

WMECO

 

 3.3 

 

 

 2.9 

 

 

 3.3 

 


The following table summarizes average useful lives of depreciable assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Depreciable Life

(Years)

NU

 

CL&P

 

NSTAR Electric

 

PSNH

 

WMECO

Distribution

 

 34.9 

 

 

 37.5 

 

 

 32.3 

 

 

 32.3 

 

 

 30.9 

Transmission

 

 42.5 

 

 

 39.8 

 

 

 44.0 

 

 

 43.7 

 

 

 49.9 

Generation

 

 31.9 

 

 

 -  

 

 

 -  

 

 

 32.1 

 

 

 25.0 

Other

 

 14.2 

 

 

 -  

 

 

 -  

 

 

 -  

 

 

 -  


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 contract settlements are recovered from, or refunded to, customers in their respective energy supply rates.  For NU's unregulated wholesale marketing contracts that expired on December 31, 2013, changes in fair values of derivatives were included in Net Income.  


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


 

 

As of December 31,

 

 

2014 

 

2013 

 

 

Commodity Supply

 

 

 

Net Amount

 

Commodity Supply

 

 

 

Net Amount

 

 

and Price Risk

 

 

 

 

Recorded as

 

and Price Risk

 

 

 

 

 

Recorded as

(Millions of Dollars)

 Management

 

Netting (1)

 

a Derivative

 

 Management

 

Netting (1)

 

a Derivative

Current Derivative Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Level 2:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NU

$

 - 

 

$

 - 

 

$

 - 

 

$

 1.9 

 

$

 (0.3)

 

$

 1.6 

Level 3:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NU

 

16.2 

 

 

 (6.6)

 

 

 9.6 

 

 

 18.4 

 

 

 (9.8)

 

 

 8.6 

 

CL&P

 

16.1 

 

 

 (6.6)

 

 

 9.5 

 

 

 17.1 

 

 

 (9.8)

 

 

 7.3 

 

NSTAR Electric

 

0.1 

 

 

 -   

 

 

 0.1 

 

 

 1.2 

 

 

 - 

 

 

 1.2 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-Term Derivative Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Level 2:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NU

$

 - 

 

$

 - 

 

$

 - 

 

$

 0.2 

 

$

 - 

 

$

 0.2 

Level 3:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NU

 

 93.5 

 

 

 (19.2)

 

 

 74.3 

 

 

 116.2 

 

 

 (42.2)

 

 

 74.0 

 

CL&P

 

 93.5 

 

 

 (19.2)

 

 

 74.3 

 

 

 113.6 

 

 

 (42.2)

 

 

 71.4 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Derivative Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Level 2:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NU

$

 (9.8)

 

$

 - 

 

$

 (9.8)

 

$

 - 

 

$

 - 

 

$

 - 

Level 3:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NU

 

 (90.0)

 

 

 - 

 

 

 (90.0)

 

 

 (93.7)

 

 

 - 

 

 

 (93.7)

 

CL&P

 

 (88.5)

 

 

 - 

 

 

 (88.5)

 

 

 (92.2)

 

 

 - 

 

 

 (92.2)

 

NSTAR Electric

 

 (1.5)

 

 

 - 

 

 

 (1.5)

 

 

 (1.5)

 

 

 - 

 

 

 (1.5)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Level 2:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NU

$

 (0.3)

 

$

 - 

 

$

 (0.3)

 

$

 - 

 

$

 - 

 

$

 - 

Level 3:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NU

 

 (409.3)

 

 

 - 

 

 

 (409.3)

 

 

 (624.1)

 

 

 - 

 

 

 (624.1)

 

CL&P

 

 (406.2)

 

 

 - 

 

 

 (406.2)

 

 

 (617.1)

 

 

 - 

 

 

 (617.1)

 

NSTAR Electric

 

 (3.1)

 

 

 - 

 

 

 (3.1)

 

 

 (7.0)

 

 

 - 

 

 

 (7.0)




102


(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.


The business activities that result in the recognition of derivative assets also create exposure to various counterparties.  As of December 31, 2014, NU and CL&P's derivative assets were exposed to counterparty credit risk.  Of NU's and CL&P's derivative assets, $64 million was contracted with investment grade entities.


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


Derivative Contracts At Fair Value with Offsetting Regulatory Amounts

Commodity Supply and Price Risk Management:  As required by regulation, CL&P, along with UI, has capacity-related contracts with generation facilities.  CL&P has a sharing agreement with UI, with 80 percent of each contract allocated to CL&P and 20 percent allocated to UI.  The combined capacity of these contracts is 787 MW.  The capacity contracts extend through 2026 and obligate both CL&P and UI to make or receive payments on a monthly basis to or from the generation facilities based on the difference between a set capacity price and the 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 December 31, 2014 and 2013, NU had NYMEX future contracts in order to reduce variability associated with the purchase price of approximately 8.8 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:


 

 

 

Gain/(Loss) Recognized on Derivatives

(Millions of Dollars)

 

 

For the Years Ended December 31,

NU

 

 

2014 

 

2013 

 

2012 

Balance Sheets:

 

 

 

 

 

 

 

 

 

 

 

Regulatory Assets and Liabilities

 

 

$

 134.4 

 

$

 160.6 

 

$

 (29.0)

Statements of Income:

 

 

 

 

 

 

 

 

 

 

 

Purchased Power, Fuel and Transmission

 

 

 

 - 

 

 

 1.0 

 

 

 (0.7)


Credit Risk

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


Fair Value Measurements of Derivative Instruments

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


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


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




103


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 December 31,

 

2014 

 

2013 

 

 

Range

 

Period Covered

 

 

Range

 

Period Covered

Energy Prices:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  NU

$

52 

per MWh

 

2020 

 

$

49 

-

77 

per MWh

 

2018 - 2029

  CL&P

$

52 

per MWh

 

2020 

 

$

56 

-

58 

per MWh

 

2018 - 2029

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Capacity Prices:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  NU

$

5.30 

-

 12.98 

per kW-Month

 

2016 - 2026

 

$

5.07 

-

11.82 

per kW-Month

 

2017 - 2029

  CL&P

$

11.08 

-

 12.98 

per kW-Month

 

2018 - 2026

 

$

5.07 

-

10.42 

per kW-Month

 

2017 - 2026

  NSTAR Electric

$

5.30 

-

 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

 

2015 - 2024

 

$

3.30

per kW-Month

 

2014 - 2024

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

REC Prices:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  NU

$

38 

-

56 

per REC

 

2015 - 2018

 

$

36 

-

87 

 

per REC

2014 - 2029

  NSTAR Electric

$

38 

-

56 

per REC

 

2015 - 2018

 

$

36 

-

70 

 

per REC

2014 - 2018


Exit price premiums of 7 percent through 24 percent are also applied on these contracts and reflect the most recent market activity available for similar type contracts.


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


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


(Millions of Dollars)

NU

 

CL&P

 

NSTAR Electric

Derivatives, Net:

 

 

 

 

 

 

 

 

Fair Value as of January 1, 2013

$

 (878.6)

 

$

 (866.2)

 

$

 (14.9)

Net Realized/Unrealized Gains Included in:

 

 

 

 

 

 

 

 

 

Net Income (1)

 

 10.9 

 

 

 - 

 

 

 - 

 

Regulatory Assets and Liabilities

 

 158.3 

 

 

 148.9 

 

 

 3.5 

Settlements

 

 74.2 

 

 

 86.7 

 

 

 4.1 

Fair Value as of December 31, 2013

$

 (635.2)

 

$

 (630.6)

 

$

 (7.3)

Net Realized/Unrealized Gains Included in

   Regulatory Assets and Liabilities

 

 141.3 

 

 

 139.7 

 

 

 4.3 

Settlements

 

 78.5 

 

 

 80.0 

 

 

 (1.5)

Fair Value as of December 31, 2014

$

 (415.4)

 

$

 (410.9)

 

$

 (4.5)


(1)

The Net Income impact for the year ended December 31, 2013 related to the unregulated wholesale marketing sales contract that was offset by the losses on the unregulated sourcing contracts classified as Level 2 in the fair value hierarchy, resulting in a total net gain of $1 million.


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.


The Company elected to record mutual funds 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 December 31, 2014 and 2013, the mutual funds and equity investments were classified as Level 1 in the fair value hierarchy and totaled $85.1 million and $57.2 million, respectively.  For the years ended December 31, 2014, 2013 and 2012, net gains on these securities of $1.9 million, $10.2 million and $5.9 million, respectively, were recorded in Other Income, Net on the statements of income.  Dividend income is recorded in Other Income, Net when dividends are declared.  All other marketable securities are accounted for as available-for-sale.  




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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 are included in current and long-term Marketable Securities on the balance sheets.


 

 

As of December 31,

 

 

2014 

 

2013 

 

 

 

 

 

Pre-Tax

 

Pre-Tax

 

 

 

 

 

 

 

Pre-Tax

 

Pre-Tax

 

 

 

 

 

Amortized

 

Unrealized

 

Unrealized

 

 

 

 

Amortized

 

Unrealized

 

Unrealized

 

 

 

(Millions of Dollars)

Cost

 

Gains

 

Losses

 

Fair Value

 

Cost

 

Gains

 

Losses

 

Fair Value

NU

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Debt Securities (1)

$

 313.0 

 

$

 7.5 

 

$

 (0.3)

 

$

 320.2 

 

$

 299.2 

 

$

 2.5 

 

$

 (2.1)

 

$

 299.6 

 

Equity Securities (1)

 

 160.6 

 

 

 73.3 

 

 

 - 

 

 

 233.9 

 

 

 163.6 

 

 

 60.5 

 

 

 - 

 

 

 224.1 

WMECO  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Debt Securities (2)

 

 58.2 

 

 

 - 

 

 

 (0.1)

 

 

 58.1 

 

 

 57.9 

 

 

 - 

 

 

 - 

 

 

 57.9 


(1)

NU's amounts include CYAPC's and YAEC's marketable securities held in nuclear decommissioning trusts of $450.8 million and $424 million as of December 31, 2014 and 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 recorded in Marketable Securities with the corresponding offset to Other Long-Term Liabilities on the balance sheets, with no impact on the statements of income.  All of the equity securities accounted for as available-for-sale securities are held in the CYAPC and YAEC trusts.


(2)

Unrealized gains and losses on debt securities held by WMECO are recorded in Marketable Securities with the corresponding offset to Other Long-Term Assets on the balance sheets.  


Unrealized Losses and Other-than-Temporary Impairment:  There have been no significant unrealized losses, other-than-temporary impairments or credit losses for 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 December 31, 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)

$

 55.0 

 

$

 55.0 

 

$

 28.7 

 

$

 28.7 

One to five years

 

 88.8 

 

 

 89.1 

 

 

 25.8 

 

 

 25.8 

Six to ten years

 

 66.0 

 

 

 67.7 

 

 

 0.7 

 

 

 0.7 

Greater than ten years

 

 103.2 

 

 

 108.4 

 

 

 3.0 

 

 

 2.9 

Total Debt Securities

$

 313.0 

 

$

 320.2 

 

$

 58.2 

 

$

 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 December 31,

 

As of December 31,

(Millions of Dollars)

2014 

 

2013 

 

2014 

 

2013 

Level 1:  

 

 

 

 

 

 

 

 

 

 

 

 

Mutual Funds and Equities

$

 319.0 

 

$

 281.3 

 

$

 - 

 

$

 - 

 

Money Market Funds

 

 24.9 

 

 

 32.9 

 

 

 4.3 

 

 

 10.9 

Total Level 1

$

 343.9 

 

$

 314.2 

 

$

 4.3 

 

$

 10.9 

Level 2:

 

 

 

 

 

 

 

 

 

 

 

 

U.S. Government Issued Debt Securities

    (Agency and Treasury)

$

 51.3 

 

$

 61.4 

 

$

 - 

 

$

 6.8 

 

Corporate Debt Securities

 

 49.1 

 

 

 53.6 

 

 

 14.7 

 

 

 15.1 

 

Asset-Backed Debt Securities

 

 54.1 

 

 

 30.4 

 

 

 14.5 

 

 

 9.0 

 

Municipal Bonds

 

 116.3 

 

 

 105.5 

 

 

 13.0 

 

 

 11.2 

 

Other Fixed Income Securities

 

 24.5 

 

 

 15.8 

 

 

 11.6 

 

 

 4.9 

Total Level 2

$

 295.3 

 

$

 266.7 

 

$

 53.8 

 

$

 47.0 

Total Marketable Securities

$

 639.2 

 

$

 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



105


maturity dates, and tranche information.  Municipal bonds are valued using a market approach that incorporates reported trades and benchmark yields.  Other fixed income securities are valued using pricing models, quoted prices of securities with similar characteristics, and discounted cash flows.


6.

ASSET RETIREMENT OBLIGATIONS


NU, including CL&P, NSTAR Electric, PSNH and WMECO, recognizes a liability for the fair value of an ARO on the obligation date if the liability's fair value can be reasonably estimated and is conditional on a future event.  Settlement dates and future costs are reasonably estimated when sufficient information becomes available.  Management has identified various categories of AROs, primarily certain assets containing asbestos and hazardous contamination and has performed fair value calculations, reflecting expected probabilities for settlement scenarios.


The fair value of an ARO is recorded as a liability in Other Long-Term Liabilities with a corresponding amount included in Property, Plant and Equipment, Net on the balance sheets.  The ARO assets are depreciated, and the ARO liabilities are accreted over the estimated life of the obligation with corresponding credits recorded as accumulated depreciation and ARO liabilities, respectively.  As the Regulated companies are rate-regulated on a cost-of-service basis, these companies apply regulatory accounting guidance and both the depreciation and accretion costs associated with the Regulated companies' AROs are recorded as increases to Regulatory Assets on the balance sheets.  


A reconciliation of the beginning and ending carrying amounts of ARO liabilities are as follows:


NU

 

 

 

 

 

 

As of December 31,

(Millions of Dollars)

2014 

 

2013 

Balance as of Beginning of Year

$

 424.9 

 

$

 412.2 

Liabilities Incurred During the Year

 

 1.3 

 

 

 0.1 

Liabilities Settled During the Year

 

 (19.5)

 

 

 (13.8)

Accretion

 

 25.1 

 

 

 23.8 

Revisions in Estimated Cash Flows

 

 (5.5)

 

 

 2.6 

Balance as of End of Year

$

 426.3 

 

$

 424.9 


 

 

 

 

 

As of December 31,

 

 

 

 

 

2014 

 

2013 

 

 

 

 

NSTAR

 

 

 

 

 

 

 

NSTAR

 

 

 

 

(Millions of Dollars)

 

CL&P

 

Electric

 

PSNH

 

WMECO

 

CL&P

 

Electric

 

PSNH

 

WMECO

Balance as of Beginning of Year

 

$

 35.0 

 

$

 32.8 

 

$

 19.5 

 

$

 4.5 

 

$

 33.6 

 

$

 31.4 

 

$

 18.4 

 

$

 4.3 

Liabilities Incurred During the Year

 

 

 -  

 

 

 -  

 

 

 -  

 

 

 1.1 

 

 

 -  

 

 

 -  

 

 

 -  

 

 

 -  

Liabilities Settled During the Year

 

 

 (1.1)

 

 

 -  

 

 

 -  

 

 

 -  

 

 

 (0.7)

 

 

 (0.1)

 

 

 -  

 

 

 -  

Accretion

 

 

 1.9 

 

 

 1.5 

 

 

 1.1 

 

 

 0.3 

 

 

 2.2 

 

 

 1.5 

 

 

 1.2 

 

 

 0.3 

Revisions in Estimated Cash Flows

 

 

 (0.5)

 

 

 -  

 

 

 -  

 

 

 -  

 

 

 (0.1)

 

 

 -  

 

 

 (0.1)

 

 

 (0.1)

Balance as of End of Year

 

$

 35.3 

 

$

 34.3 

 

$

 20.6 

 

$

 5.9 

 

$

 35.0 

 

$

 32.8 

 

$

 19.5 

 

$

 4.5 


NU's amounts include CYAPC and YAEC's AROs of $317.3 million and $318.8 million as of December 31, 2014 and 2013, respectively.  The fair value of the ARO for CYAPC and YAEC includes uncertainties of the fuel off-load dates related to the DOE's timing of performance regarding its obligation to dispose of the spent nuclear fuel and high level waste.  The incremental asset recorded as an offset to the ARO liability was fully depreciated since the plants have no remaining useful life.  Any changes in the assumptions used to calculate the fair value of the ARO liability are recorded with a corresponding offset to the related regulatory asset.  The assets held in the CYAPC and YAEC nuclear decommissioning trusts are restricted for settling the ARO and all other decommissioning obligations.  For further information on the assets held in the nuclear decommissioning trusts, see Note 5, "Marketable Securities," to the financial statements.


7.

SHORT-TERM DEBT


Short-Term Borrowing Limits:  The amount of short-term borrowings that may be incurred by CL&P, NSTAR Electric and WMECO is subject to periodic approval by the FERC.  As a result of the NHPUC having jurisdiction over PSNH's short-term debt, PSNH is not currently required to obtain FERC approval for its short-term borrowings.  On July 31, 2013, the FERC granted authorization to allow CL&P and WMECO to incur total short-term borrowings up to a maximum of $600 million and $300 million, respectively, effective January 1, 2014 through December 31, 2015.  On June 11, 2014, the FERC granted authorization to allow NSTAR Electric to issue total short-term debt securities in an aggregate principal amount not to exceed $655 million outstanding at any one time, effective October 24, 2014 through October 23, 2016.  


PSNH is authorized by regulation of the NHPUC to incur short-term borrowings up to 10 percent of net fixed plant plus an additional $60 million until further ordered by the NHPUC.  As of December 31, 2014, PSNH's short-term debt authorization under the 10 percent of net fixed plant test plus $60 million totaled approximately $306 million.  


CL&P's certificate of incorporation contains preferred stock provisions restricting the amount of unsecured debt that CL&P may incur, including limiting unsecured indebtedness with a maturity of less than 10 years to 10 percent of total capitalization.  As of December 31, 2014, CL&P had $432.1 million of unsecured debt capacity available under this authorization.


Yankee Gas and NSTAR Gas are not required to obtain approval from any state or federal authority to incur short-term debt.


Credit Agreements and Commercial Paper Programs:  NU parent, CL&P, PSNH, WMECO, NSTAR Gas and Yankee Gas are parties to a five-year $1.45 billion revolving credit facility.  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.  Effective July 23, 2014, NU parent, CL&P, PSNH, WMECO, NSTAR Gas and Yankee Gas extended the expiration date of their joint revolving credit facility for one additional



106


year to September 6, 2019.  CL&P has a borrowing sublimit of $600 million and PSNH and WMECO each have borrowing sublimits of $300 million.  As of December 31, 2014 and 2013, NU had approximately $1.1 billion and $1.01 billion, respectively, in short-term borrowings outstanding under the NU parent commercial paper program, leaving $348.9 million and $435.5 million of available borrowing capacity as of December 31, 2014 and 2013, respectively.  The weighted-average interest rate on these borrowings as of December 31, 2014 and 2013 was 0.43 percent and 0.24 percent, respectively, which is generally based on A2/P2 rated commercial paper.  As of December 31, 2014, there were intercompany loans from NU of $133.4 million to CL&P, $90.5 million to PSNH and $21.4 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.  


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


Except as described below, amounts outstanding under the commercial paper programs are 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.  Intercompany loans from NU to CL&P, PSNH and WMECO are eliminated in consolidation in NU's balance sheets.


On January 15, 2015, NU parent issued $150 million of 1.60 percent Series G Senior Notes due to mature in 2018 and $300 million of 3.15 percent Series H Senior Notes, due to mature in 2025.  The proceeds, net of issuance costs, were used to repay short-term borrowings outstanding under the NU commercial paper program.  As the debt issuances refinanced short-term debt, the short-term debt was classified as Long-Term Debt as of December 31, 2014.  On January 2, 2014, Yankee Gas issued $100 million of Series L First Mortgage Bonds and $25 million of the proceeds was used to repay short-term borrowings outstanding under the NU commercial paper program.  As the debt issuance refinanced short-term debt, these amounts were classified as Long-Term Debt on NU's balance sheet as of December 31, 2013.  See Note 8, "Long-Term Debt" for further information on these debt issuances.


Under the credit facilities, NU and its subsidiaries must comply with certain financial and non-financial covenants, including a consolidated debt to total capitalization ratio.  As of December 31, 2014 and 2013, NU and its subsidiaries were in compliance with these covenants.  If NU or its subsidiaries were not in compliance with these covenants, an event of default would occur requiring all outstanding borrowings by such borrower to be repaid and additional borrowings by such borrower would not be permitted under its respective credit facility.  


8.

LONG-TERM DEBT


Details of long-term debt outstanding are as follows:


CL&P

As of December 31,

(Millions of Dollars)

2014 

 

2013 

First Mortgage Bonds:

 

 

 

 

 

 

7.875% 1994 Series D due 2024

$

 139.8 

 

$

 139.8 

 

4.800% 2004 Series A due 2014 (1)

 

 -  

 

 

 150.0 

 

5.750% 2004 Series B due 2034

 

 130.0 

 

 

 130.0 

 

5.000% 2005 Series A due 2015

 

 100.0 

 

 

 100.0 

 

5.625% 2005 Series B due 2035

 

 100.0 

 

 

 100.0 

 

6.350% 2006 Series A due 2036

 

 250.0 

 

 

 250.0 

 

5.375% 2007 Series A due 2017

 

 150.0 

 

 

 150.0 

 

5.750% 2007 Series B due 2037

 

 150.0 

 

 

 150.0 

 

5.750% 2007 Series C due 2017

 

 100.0 

 

 

 100.0 

 

6.375% 2007 Series D due 2037

 

 100.0 

 

 

 100.0 

 

5.650% 2008 Series A due 2018

 

 300.0 

 

 

 300.0 

 

5.500% 2009 Series A due 2019

 

 250.0 

 

 

 250.0 

 

2.500% 2013 Series A due 2023

 

 400.0 

 

 

 400.0 

 

4.300% 2014 Series A due 2044 (2)

 

 250.0 

 

 

 -  

Total First Mortgage Bonds

 

 2,419.8 

 

 

 2,319.8 

Pollution Control Revenue Bonds:

 

 

 

 

 

 

4.375% Fixed Rate Tax Exempt due 2028

 

 120.5 

 

 

 120.5 

 

1.550% Fixed Rate Tax Exempt due 2031 (3)

 

 62.0 

 

 

 62.0 

Total Pollution Control Revenue Bonds

 

 182.5 

 

 

 182.5 

Spent Nuclear Fuel Obligation

 

 244.5 

 

 

 244.4 

Less Amounts due Within One Year

 

 (162.0)

 

 

 (150.0)

Unamortized Premiums and Discounts, Net

 

 (4.8)

 

 

 (5.5)

CL&P Long-Term Debt

$

 2,680.0 

 

$

 2,591.2 




107






NSTAR Electric

As of December 31,

(Millions of Dollars)

2014 

 

2013 

Debentures:

 

 

 

 

 

 

4.875% due 2014 (4)

$

 -  

 

$

 300.0 

 

5.750% due 2036

 

 200.0 

 

 

 200.0 

 

5.625% due 2017

 

 400.0 

 

 

 400.0 

 

5.500% due 2040

 

 300.0 

 

 

 300.0 

 

2.375% due 2022

 

 400.0 

 

 

 400.0 

 

Variable Rate due 2016 (5)

 

 200.0 

 

 

 200.0 

 

4.400% due 2044 (4)

 

 300.0 

 

 

 -  

Total Debentures

 

 1,800.0 

 

 

 1,800.0 

Bonds:

 

 

 

 

 

 

7.375% Tax Exempt Sewage Facility Revenue Bonds, due 2015

 

 4.7 

 

 

 6.4 

Total Bonds

 

 4.7 

 

 

 6.4 

Less Amounts due Within One Year

 

 (4.7)

 

 

 (301.7)

Unamortized Premiums and Discounts, Net

 

 (7.3)

 

 

 (5.3)

NSTAR Electric Long-Term Debt

$

 1,792.7 

 

$

 1,499.4 

 

  

 

 

 

 

 

PSNH

As of December 31,

(Millions of Dollars)

2014 

 

2013 

First Mortgage Bonds:

 

 

 

 

 

 

5.25% Series L due 2014 (6)

$

 -  

 

$

 50.0 

 

5.60% Series M due 2035

 

 50.0 

 

 

 50.0 

 

6.15% Series N due 2017

 

 70.0 

 

 

 70.0 

 

6.00% Series O due 2018

 

 110.0 

 

 

 110.0 

 

4.50% Series P due 2019

 

 150.0 

 

 

 150.0 

 

4.05% Series Q due 2021

 

 122.0 

 

 

 122.0 

 

3.20% Series R due 2021

 

 160.0 

 

 

 160.0 

 

3.50% Series S due 2023 (7)

 

 325.0 

 

 

 250.0 

Total First Mortgage Bonds

 

 987.0 

 

 

 962.0 

Pollution Control Revenue Bonds:

 

 

 

 

 

 

Adjustable Rate Tax Exempt Series A due 2021

 

 89.3 

 

 

 89.3 

Total Pollution Control Revenue Bonds

 

 89.3 

 

 

 89.3 

Less Amounts due Within One Year

 

 -  

 

 

 (50.0)

Unamortized Premiums and Discounts, Net

 

 -  

 

 

 (2.3)

PSNH Long-Term Debt

$

 1,076.3 

 

$

 999.0 


WMECO

As of December 31,

(Millions of Dollars)

2014 

 

2013 

Notes:

 

 

 

 

 

 

5.90% Senior Notes Series B, due 2034

$

 50.0 

 

$

 50.0 

 

5.24% Senior Notes Series C, due 2015

 

 50.0 

 

 

 50.0 

 

6.70% Senior Notes Series D, due 2037

 

 40.0 

 

 

 40.0 

 

5.10% Senior Notes Series E, due 2020

 

 95.0 

 

 

 95.0 

 

3.50% Senior Notes Series F, due 2021

 

 250.0 

 

 

 250.0 

 

3.88% Senior Notes Series G, due 2023

 

 80.0 

 

 

 80.0 

Total Notes

 

 565.0 

 

 

 565.0 

Spent Nuclear Fuel Obligation

 

 57.4 

 

 

 57.3 

Less Amounts due Within One Year

 

 (50.0)

 

 

 -  

Unamortized Premiums and Discounts, Net

 

 6.1 

 

 

 7.1 

WMECO Long-Term Debt

$

 578.5 

 

$

 629.4 

 

  

 

 

 

 

 




108






OTHER

As of December 31,

(Millions of Dollars)

2014 

 

 

2013 

Yankee Gas - First Mortgage Bonds:

 

 

 

 

 

 

8.48% Series B due 2022

$

 20.0 

 

$

 20.0 

 

4.80% Series G due 2014  (8)

 

 -  

 

 

 75.0 

 

5.26% Series H due 2019

 

 50.0 

 

 

 50.0 

 

5.35% Series I due 2035

 

 50.0 

 

 

 50.0 

 

6.90% Series J due 2018

 

 100.0 

 

 

 100.0 

 

4.87% Series K due 2020

 

 50.0 

 

 

 50.0 

 

4.82% Series L due 2044  (8)

 

 100.0 

 

 

 -  

Total First Mortgage Bonds

 

 370.0 

 

 

 345.0 

Unamortized Premium

 

 0.6 

 

 

 0.7 

Yankee Gas Long-Term Debt

 

 370.6 

 

 

 345.7 

 

  

 

 

 

 

 

NSTAR Gas - First Mortgage Bonds:

 

 

 

 

 

 

9.95% Series J due 2020

 

 25.0 

 

 

 25.0 

 

7.11% Series K due 2033

 

 35.0 

 

 

 35.0 

 

7.04% Series M due 2017

 

 25.0 

 

 

 25.0 

 

4.46% Series N due 2020

 

 125.0 

 

 

 125.0 

NSTAR Gas Long-Term Debt

 

 210.0 

 

 

 210.0 

 

  

 

 

 

 

 

Other - Notes and Debentures:

 

 

 

 

 

 

1.45% Senior Notes Series E due 2018 (NU Parent)

 

 300.0 

 

 

 300.0 

 

2.80% Senior Notes Series F due 2023 (NU Parent)

 

 450.0 

 

 

 450.0 

 

4.50% Debentures due 2019 (NU Parent)  

 

 350.0 

 

 

 350.0 

 

NU Commercial Paper Borrowings(8) (9)

 

 446.3 

 

 

 25.0 

 

Spent Nuclear Fuel Obligation (CYAPC)

 

 179.4 

 

 

 179.4 

Total Other Notes and Debentures

 

 1,725.7 

 

 

 1,304.4 

Fair Value Adjustment (10)

 

 202.3 

 

 

 230.7 

Less Amounts due Within One Year   

 

 -  

 

 

 -  

Less Fair Value Adjustment - Current Portion (10)

 

 (28.9)

 

 

 (31.7)

Unamortized Premiums and Discounts, Net

 

 (1.2)

 

 

 (1.3)

Total Other Long-Term Debt

$

 2,478.5 

 

$

 2,057.8 

 

  

 

 

 

 

 

Total NU Long-Term Debt

$

 8,606.0 

 

$

 7,776.8 


(1)

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


(2)

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.  


(3)

On February 12, 2015, CL&P notified the trustee that it intends to purchase and cancel the bonds on April 1, 2015, after they have been tendered by the bondholders.


(4)

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.  


(5)

As of December 31, 2014 and 2013, the interest rate was 0.4721 percent and 0.478 percent, respectively.


(6)

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


(7)

On October 14, 2014, PSNH issued $75 million of first mortgage bonds at a yield of 3.144 percent due to mature in 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.  The proceeds, net of issuance costs, were used to repay short-term borrowings.  


(8)

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, these amounts were classified as Long-Term Debt on NU's balance sheet as of December 31, 2013.


(9)

On January 15, 2015, NU parent issued $150 million of 1.60 percent Series G Senior Notes due to mature in 2018 and $300 million of 3.15 percent Series H Notes, due to mature in 2025.  The proceeds, net of issuance costs, were used to repay short-term borrowings outstanding under the NU commercial paper program.  As the debt issuances refinanced short-term debt, the short-term debt was classified as Long-Term Debt as of December 31, 2014.  


(10)

Amount relates to the purchase price adjustment required to record the NSTAR long-term debt at fair value on the date of the merger.




109


Long-term debt maturities, mandatory tender payments and cash sinking fund requirements on debt outstanding for the years 2015 through 2019 and thereafter are shown below.  These amounts exclude the spent nuclear fuel obligation, net unamortized premiums and discounts, and other fair value adjustments as of December 31, 2014:


(Millions of Dollars)

NU

 

CL&P

 

NSTAR Electric

 

PSNH

 

WMECO

2015 

$

 216.7 

 

$

 162.0 

 

$

 4.7 

 

$

 -   

 

$

 50.0 

2016 

 

 200.0 

 

 

 -   

 

 

 200.0 

 

 

 -   

 

 

 -   

2017 

 

 745.0 

 

 

 250.0 

 

 

 400.0 

 

 

 70.0 

 

 

 -   

2018 

 

 810.0 

 

 

 300.0 

 

 

 -   

 

 

 110.0 

 

 

 -   

2019 

 

 800.0 

 

 

 250.0 

 

 

 -   

 

 

 150.0 

 

 

 -   

Thereafter

 

 4,956.6 

 

 

 1,640.3 

 

 

 1,200.0 

 

 

 746.3 

 

 

 515.0 

Total

$

 7,728.3 

 

$

 2,602.3 

 

$

 1,804.7 

 

$

 1,076.3 

 

$

 565.0 


The utility plant of CL&P, PSNH, Yankee Gas and NSTAR Gas is subject to the lien of each company's respective first mortgage bond indenture.  The NSTAR Electric, WMECO and NU parent debt is unsecured.  


CL&P's obligation to repay each series of PCRBs is secured by first mortgage bonds.  Each such series of first mortgage bonds contains similar terms and provisions as the applicable series of PCRBs.  If CL&P fails to meet its obligations under the first mortgage bonds, then the holder of the first mortgage bonds (the issuer of the PCRBs) would have rights under the first mortgage bonds.  CL&P's $62 million tax-exempt PCRBs, which are subject to mandatory tender for purchase on April 1, 2015 and carry a coupon rate of 1.55 percent during the current three-year fixed rate period, cannot be redeemed prior to its tender date.  CL&P's $120.5 million tax-exempt PCRBs will be subject to redemption at par on or after September 1, 2021.  All other long-term debt securities are subject to make-whole provisions.    


PSNH's obligation to repay the PCRBs is secured by first mortgage bonds and bond insurance.  The first mortgage bonds contain similar terms and provisions as the PCRBs.  If PSNH fails to meet its obligations under the first mortgage bonds, then the holder of the first mortgage bonds (the issuer of the PCRBs) would have rights under the first mortgage bonds.  The PSNH Series A tax-exempt PCRBs are currently callable at 100 percent of par.  The PCRBs bear interest at a rate that is periodically set pursuant to auctions.  PSNH is not obligated to purchase these PCRBs, which mature in 2021, from the remarketing agent.  As of December 31, 2014 and 2013, the interest rate was 0.175 percent and 0.088 percent, respectively.  


The long-term debt agreements provide that NU and certain of its subsidiaries must comply with certain covenants as are customarily included in such agreements, including a minimum equity requirement for NSTAR Gas.  Under the minimum equity requirement, the outstanding long-term debt of NSTAR Gas must not exceed equity.  


Yankee Gas has certain long-term debt agreements that contain cross-default provisions. No other debt issuances contain cross-default provisions as of December 31, 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.


On October 3, 2014, FERC granted authorization to allow NPT to issue short-term and long-term debt securities in an aggregate amount not to exceed $500 million outstanding at any one time, effective December 31, 2014 through December 31, 2016.


On November 26, 2014, PURA approved Yankee Gas' request to extend the authorization period for issuance of up to $200 million in long-term debt from December 31, 2014 to December 31, 2015.


On January 12, 2015, NSTAR Gas filed an application with the DPU requesting authorization to issue up to $100 million in long-term debt for the period ending December 31, 2015.


Spent Nuclear Fuel Obligation:  Under the Nuclear Waste Policy Act of 1982, CL&P and WMECO must pay the DOE for the costs of disposal of spent nuclear fuel and high-level radioactive waste for the period prior to the sale of their ownership shares in the Millstone nuclear power stations.  The Millstone Nuclear Generating station was made up of Millstone 1, Millstone 2, and Millstone 3 and all three units were sold in March 2001.


The DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste.  For nuclear fuel used to generate electricity prior to April 7, 1983 (Prior Period Spent Nuclear Fuel) for CL&P and WMECO, an accrual has been recorded for the full liability, and payment must be made by CL&P and WMECO to the DOE prior to the first delivery of spent fuel to the DOE.  After the sale of Millstone, CL&P and WMECO remained responsible for their share of the disposal costs associated with the Prior Period Spent Nuclear Fuel.  Until such payment to the DOE is made, the outstanding liability will continue to accrue interest at the 3-month Treasury bill yield rate.  In addition, as a result of consolidating CYAPC, NU has consolidated $179.4 million in additional spent nuclear fuel obligations, including interest, as of both December 31, 2014 and 2013.  The obligation due to the DOE for the disposal of CL&P's and WMECO's Prior Period Spent Nuclear Fuel and CYAPC's spent nuclear fuel obligation include accumulated interest costs of $350.4 million and $350.3 million ($178 million and $177.9 million for CL&P and $41.8 million and $41.7 million for WMECO) as of December 31, 2014 and 2013, respectively.


WMECO and CYAPC maintain trusts to fund amounts due to the DOE for the disposal of spent nuclear fuel.  For further information on these trusts, see Note 5, "Marketable Securities," to the financial statements.




110


9.

EMPLOYEE BENEFITS


A.

Pension Benefits and Postretirement Benefits Other Than Pensions

As of December 31, 2014, NUSCO sponsored two defined benefit retirement plans that covered eligible employees, including employees of CL&P, NSTAR Electric, PSNH and WMECO (NUSCO Pension Plan and NSTAR Pension Plan).  Effective January 1, 2015, the two plans were merged into one plan, sponsored by NUSCO.  The NUSCO and NSTAR Pension Plans are subject to the provisions of ERISA, as amended by the PPA of 2006. NU's policy is to annually fund the Pension Plans in an amount at least equal to an amount that will satisfy federal requirements. In addition, NU maintains non-qualified defined benefit retirement plans sponsored by NUSCO (herein collectively referred to as the SERP Plans), which provide benefits in excess of Internal Revenue Code limitations to eligible current and retired participants.  


As of December 31, 2014, NUSCO also sponsored defined benefit postretirement plans that provide certain retiree benefits, primarily medical, dental and life insurance, to retiring employees that meet certain age and service eligibility requirements (NUSCO PBOP Plans and NSTAR PBOP Plan).  Effective January 1, 2015, the plans were merged into one plan, sponsored by NUSCO.  Under certain circumstances, eligible retirees are required to contribute to the costs of postretirement benefits.  The benefits provided under the PBOP Plans are not vested and the Company has the right to modify any benefit provision subject to applicable laws at that time.


Because the Regulated companies recover the retiree benefit costs from customers through rates, regulatory assets are recorded in lieu of an adjustment to Accumulated Other Comprehensive Income/(Loss) to record the funded status of the Pension, SERP and PBOP Plans.  Regulatory accounting was also applied to the portions of the NUSCO costs that support the Regulated companies, as these costs are also recovered from customers.  Adjustments to the Pension and PBOP funded status for the unregulated companies are recorded on an after-tax basis to Accumulated Other Comprehensive Income/(Loss).  For further information, see Note 2, "Regulatory Accounting," and Note 14, "Accumulated Other Comprehensive Income/(Loss)," to the financial statements.  The SERP Plans do not have plan assets.


For the years ended December 31, 2014 and 2013, the expected return on plan assets for the NUSCO Pension and PBOP Plans was calculated by applying the assumed rate of return to a four-year rolling average of plan asset fair values. This calculation recognized investment gains or losses over a four-year period from the years in which they occurred. Investment gains or losses for this purpose are the difference between the calculated expected return and the actual return. As investment gains and losses are reflected in the average plan asset fair values, they are subject to amortization with other unrecognized actuarial gains or losses. For the NSTAR Pension and PBOP Plans, the entire difference between the actual return and calculated expected return on plan assets is reflected as a component of unrecognized actuarial gain or loss. Unrecognized actuarial gains or losses are amortized as a component of Pension and PBOP expense over the estimated average future employee service period.


Pension and SERP Plans:  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 was 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 (service company merger) and, concurrently, all employees were transferred to the company they predominantly provide services for: NUSCO, NSTAR Electric or NSTAR Gas. As a result of the employee transfers, the pension and SERP assets and liabilities were attributed by participant and transferred to the applicable company's balance sheets. This change had no impact on the income statement or net assets of NSTAR Electric or NU.  For the year ended December 31, 2014, the NUSCO and NSTAR pension and SERP plans are accounted for under the multiple-employer approach, with each company's balance sheet reflecting its share of the funded status of the plans.  The following tables provide information on the Pension and SERP Plan benefit obligations, fair values of Pension Plan assets, and funded status:


 

 

Pension and SERP

NU

As of December 31,

(Millions of Dollars)

2014 

 

2013 

Change in Benefit Obligation

 

 

 

 

 

Benefit Obligation as of Beginning of Year

$

 (4,676.5)

 

$

 (5,022.8)

Service Cost

 

 (79.9)

 

 

 (102.3)

Interest Cost

 

 (225.7)

 

 

 (206.7)

Actuarial Gain/(Loss)

 

 (739.6)

 

 

 433.6 

Benefits Paid - Pension

 

 230.3 

 

 

 216.6 

Benefits Paid - SERP

 

 5.2 

 

 

 5.1 

Benefit Obligation as of End of Year

$

 (5,486.2)

 

$

 (4,676.5)

Change in Pension Plan Assets

 

 

 

 

 

Fair Value of Plan Assets as of Beginning of Year

$

 3,985.9 

 

$

 3,411.3 

Employer Contributions

 

 171.6 

 

 

 284.7 

Actual Return on Plan Assets

 

 199.3 

 

 

 506.5 

Benefits Paid

 

 (230.3)

 

 

 (216.6)

Fair Value of Plan Assets as of End of Year

$

 4,126.5 

 

$

 3,985.9 

Funded Status as of December 31st

$

 (1,359.7)

 

$

 (690.6)




111






 

 

Pension and SERP

 

 

As of December 31, 2014

 

As of December 31, 2013

 

 

 

 

 

NSTAR

 

 

 

 

 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

(Millions of Dollars)

CL&P

 

Electric

 

PSNH

 

WMECO

 

CL&P

 

Electric (1)

 

PSNH

 

WMECO

Change in Benefit Obligation

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Benefit Obligation as of Beginning of Year

$

 (1,083.4)

 

$

 (1,353.3)

 

$

 (529.0)

 

$

 (223.9)

 

$

 (1,178.0)

 

$

 (1,430.0)

 

$

 (576.0)

 

$

 (243.1)

Decrease due to transfer of employees

 

 26.4 

 

 

 479.9 

 

 

 32.2 

 

 

 6.2 

 

 

 -  

 

 

 -  

 

 

 -  

 

 

 -  

Service Cost

 

 (20.2)

 

 

 (13.6)

 

 

 (9.7)

 

 

 (3.5)

 

 

 (24.9)

 

 

 (33.1)

 

 

 (13.1)

 

 

 (4.7)

Interest Cost

 

 (50.5)

 

 

 (41.3)

 

 

 (23.8)

 

 

 (10.3)

 

 

 (48.3)

 

 

 (58.0)

 

 

 (23.6)

 

 

 (10.0)

Actuarial Gain/(Loss)

 

 (161.0)

 

 

 (107.0)

 

 

 (73.3)

 

 

 (29.8)

 

 

 110.7 

 

 

 96.6 

 

 

 62.4 

 

 

 22.4 

Benefits Paid - Pension

 

 58.3 

 

 

 52.4 

 

 

 22.8 

 

 

 11.9 

 

 

 56.6 

 

 

 71.2 

 

 

 21.1 

 

 

 11.5 

Benefits Paid - SERP

 

 0.3 

 

 

 0.3 

 

 

 0.1 

 

 

 -  

 

 

 0.5 

 

 

 -  

 

 

 0.2 

 

 

 -  

Benefit Obligation as of End of Year

$

 (1,230.1)

 

$

 (982.6)

 

$

 (580.7)

 

$

 (249.4)

 

$

 (1,083.4)

 

$

 (1,353.3)

 

$

 (529.0)

 

$

 (223.9)

Change in Pension Plan Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fair Value of Plan Assets as of Beginning of Year

$

 1,016.3 

 

$

 1,235.3 

 

$

 528.6 

 

$

 240.4 

 

$

 937.6 

 

$

 1,069.1 

 

$

 386.6 

 

$

 218.5 

Decrease due to transfer of employees

 

 (26.4)

 

 

 (441.4)

 

 

 (32.2)

 

 

 (6.2)

 

 

 -  

 

 

 -  

 

 

 -  

 

 

 -  

Employer Contributions

 

 -  

 

 

 101.0 

 

 

 -  

 

 

 -  

 

 

 -  

 

 

 82.0 

 

 

 108.3 

 

 

 -  

Actual Return on Plan Assets

 

 49.2 

 

 

 36.5 

 

 

 24.8 

 

 

 11.7 

 

 

 135.3 

 

 

 155.4 

 

 

 54.8 

 

 

 33.4 

Benefits Paid

 

 (58.3)

 

 

 (52.4)

 

 

 (22.8)

 

 

 (11.9)

 

 

 (56.6)

 

 

 (71.2)

 

 

 (21.1)

 

 

 (11.5)

Fair Value of Plan Assets as of End of Year

$

 980.8 

 

$

 879.0 

 

$

 498.4 

 

$

 234.0 

 

$

 1,016.3 

 

$

 1,235.3 

 

$

 528.6 

 

$

 240.4 

Funded Status as of December 31st

$

 (249.3)

 

$

 (103.6)

 

$

 (82.3)

 

$

 (15.4)

 

$

 (67.1)

 

$

 (118.0)

 

$

 (0.4)

 

$

 16.5 


(1)

NSTAR Electric amounts do not include benefit obligations of the NSTAR SERP Plan as of December 31, 2013.


During 2014, the Society of Actuaries released a series of updated mortality tables resulting from recent studies that measured mortality rates for various groups of individuals.  The updated mortality tables released in 2014 increased life expectancy of plan participants by 3 to 5 years and have the effect of increasing the estimate of benefits to be provided to plan participants.  The impact of this adoption on NU's funded status liability for the year ended December 31, 2014 was an increase of approximately $340 million.  In addition, the decreases in the discount rates resulted in an increase on NU's funded status liability of approximately $530 million.  Partially offsetting these increases are the impact of other actuarial assumptions.


As of December 31, 2013, prepaid pension assets for PSNH and WMECO were included in Other Long-Term Assets on their accompanying balance sheets.  The pension and SERP benefits funded status includes the current portion of the SERP liability, which is included in Other Current Liabilities on the accompanying balance sheets.  Although NU maintains marketable securities in a supplemental benefit trust, the SERP plan itself does not contain any assets.  See Note 5, "Marketable Securities," to the financial statements.


The accumulated benefit obligation for the Pension and SERP Plans is as follows:

 

 

 

 

 

 

 

 

 

  

 

 

 

 

 

 

 

(Millions of Dollars)

NU

 

CL&P

 

NSTAR Electric (1)

 

PSNH

 

WMECO

 

2014 

$

 5,000.1 

 

$

 1,101.4 

 

$

 910.4 

 

$

 524.5 

 

$

 226.4 

 

2013 

 

 4,538.8 

 

 

 1,058.0 

 

 

 1,280.6 

 

 

 520.1 

 

 

 220.6 

 

 

 

 

 

 

 

 

 

 

  

 

 

 

 

 

 

 

(1)

NSTAR Electric amounts do not include the accumulated benefit obligation for the SERP Plan as of December 31, 2013.  

 

 

 

 

 

 

 

 

 

  

 

 

 

 

 

 

 

The following actuarial assumptions were used in calculating the Pension and SERP Plans' year end funded status:


 

 

Pension and SERP

 

 

 

 

 

 

As of December 31,

 

 

 

 

 

2014 

 

 

2013 

 

 

 

 

Discount Rate

 4.20 

%

 

 4.85 

%

-

 5.03 

%

 

 

 

 

Compensation/Progression Rate

 3.50 

%

 

 3.50 

%

-

 4.00 

%

 

 

 

 


Pension and SERP Expense:  NU charges net periodic pension expense to its subsidiaries based on the actual participant demographic data for each subsidiary's participants.  Benefit payments to participants and contributions are also tracked for each subsidiary.  The actual investment return in the trust is allocated to each of the subsidiaries annually in proportion to the investment return expected to be earned during the year. For the years ended December 31, 2013 and 2012 (prior to the service company merger), the net periodic pension expense recorded at NSTAR Electric represented the full cost of the plan with a portion of the costs allocated to affiliated companies based on participant demographic data.  




112


The components of net periodic benefit expense for the Pension and SERP Plans are shown below.  The net periodic benefit expense and the intercompany allocations less the capitalized portion of pension is included in Operations and Maintenance on the statements of income.  Capitalized pension amounts relate to employees working on capital projects and are included in Property, Plant and Equipment, Net.  Intercompany allocations are not included in the CL&P, NSTAR Electric, PSNH and WMECO net periodic benefit expense amounts.  Pension and SERP expense reflected in the statements of cash flows for CL&P, NSTAR Electric, PSNH and WMECO does not include the intercompany allocations and the corresponding capitalized portion, as these amounts are cash settled on a short-term basis.


 

Pension and SERP

 

 

For the Year Ended December 31, 2014

 

 

 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

(Millions of Dollars)

NU

 

CL&P

 

Electric

 

PSNH

 

WMECO

Service Cost

$

 79.9 

 

$

 20.2 

 

$

 13.6 

 

$

 9.7 

 

$

 3.5 

Interest Cost

 

 225.7 

 

 

 50.5 

 

 

 41.3 

 

 

 23.8 

 

 

 10.3 

Expected Return on Plan Assets

 

 (310.8)

 

 

 (75.4)

 

 

 (63.0)

 

 

 (38.1)

 

 

 (17.9)

Actuarial Loss

 

 128.4 

 

 

 33.7 

 

 

 23.5 

 

 

 11.6 

 

 

 6.9 

Prior Service Cost

 

 4.4 

 

 

 1.8 

 

 

 - 

 

 

 0.7 

 

 

 0.4 

Total Net Periodic Benefit Expense

$

 127.6 

 

$

 30.8 

 

$

 15.4 

 

$

 7.7 

 

$

 3.2 

Intercompany Allocations

 

N/A

 

$

 26.7 

 

$

 10.4 

 

$

 7.6 

 

$

 5.1 

Capitalized Pension Expense

$

 35.2 

 

$

 17.6 

 

$

 7.9 

 

$

 3.0 

 

$

 2.4 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pension and SERP

 

 

For the Year Ended December 31, 2013

 

 

 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

(Millions of Dollars)

NU

 

CL&P

 

Electric (1)

 

PSNH

 

WMECO

Service Cost

$

 102.3 

 

$

 24.9 

 

$

 33.1 

 

$

 13.1 

 

$

 4.7 

Interest Cost

 

 206.7 

 

 

 48.3 

 

 

 58.0 

 

 

 23.6 

 

 

 10.0 

Expected Return on Plan Assets

 

 (278.1)

 

 

 (73.8)

 

 

 (84.4)

 

 

 (35.4)

 

 

 (17.4)

Actuarial Loss

 

 210.5 

 

 

 55.9 

 

 

 58.1 

 

 

 21.6 

 

 

 11.8 

Prior Service Cost/(Credit)

 

 4.0 

 

 

 1.8 

 

 

 (0.3)

 

 

 0.7 

 

 

 0.4 

Total Net Periodic Benefit Expense

$

 245.4 

 

$

 57.1 

 

$

 64.5 

 

$

 23.6 

 

$

 9.5 

Intercompany Allocations

 

N/A

 

$

 44.9 

 

$

 (8.4)

 

$

 10.5 

 

$

 8.0 

Capitalized Pension Expense

$

 73.2 

 

$

 28.0 

 

$

 28.9 

 

$

 7.3 

 

$

 5.2 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pension and SERP

 

 

For the Year Ended December 31, 2012

 

 

 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

(Millions of Dollars)

NU (2)

 

CL&P

 

Electric (1)

 

PSNH

 

WMECO

Service Cost

$

 84.3 

 

$

 21.8 

 

$

 30.3 

 

$

 11.8 

 

$

 4.1 

Interest Cost

 

 198.3 

 

 

 51.2 

 

 

 58.9 

 

 

 24.4 

 

 

 10.5 

Expected Return on Plan Assets

 

 (220.9)

 

 

 (70.6)

 

 

 (65.6)

 

 

 (28.2)

 

 

 (16.4)

Actuarial Loss

 

 172.4 

 

 

 49.6 

 

 

 63.1 

 

 

 16.2 

 

 

 10.7 

Prior Service Cost/(Credit)

 

 7.9 

 

 

 3.6 

 

 

 (0.6)

 

 

 1.5 

 

 

 0.8 

Total Net Periodic Benefit Expense

$

 242.0 

 

$

 55.6 

 

$

 86.1 

 

$

 25.7 

 

$

 9.7 

Curtailments and Settlements

$

 2.2 

 

$

 - 

 

$

 - 

 

$

 - 

 

$

 - 

Intercompany Allocations

 

N/A

 

$

 42.8 

 

$

 (12.3)

 

$

 10.1 

 

$

 8.1 

Capitalized Pension Expense

$

70.6 

 

$

26.8 

 

$

30.7 

 

$

7.9 

 

$

5.1 


(1)

NSTAR Electric's allocated expense associated with the NSTAR SERP was $3.2 million and $3.6 million for the years ended December 31, 2013 and 2012, respectively, and were not included in the NSTAR Electric amounts in the tables above.  For the year ended December 31, 2014, the SERP amounts are now allocated to NSTAR Electric due to the service company merger.


(2)

NSTAR amounts were included in NU beginning April 10, 2012.


The following actuarial assumptions were used to calculate Pension and SERP expense amounts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pension and SERP

 

 

For the Years Ended December 31,

 

2014 

 

2013 

 

 

2012 

Discount Rate

 4.85 

%

-

 5.03 

%

 

 4.13 

%

-

 4.24 

%

 

 4.52 

%

-

 5.03 

%

Expected Long-Term Rate of Return

8.25  %

 

8.25  %

 

 7.30 

%

-

 8.25 

%

Compensation/Progression Rate

 3.50 

%

-

 4.00 

%

 

 3.50 

%

-

 4.00 

%

 

 3.50 

%

-

 4.00 

%




113





The following is a summary of the changes in plan assets and benefit obligations recognized in Regulatory Assets and Other Comprehensive Income (OCI) as well as amounts in Regulatory Assets and OCI reclassified as net periodic benefit expense during the years presented:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Amounts Reclassified To/From

 

 

 

 

 

 

 

Regulatory Assets

 

OCI

 

 

 

 

 

 

 

 

For the Years Ended December 31,

 

 

 

 

 

 

(Millions of Dollars)

2014 

 

2013 

 

2014 

 

2013 

 

 

 

 

 

 

Actuarial (Gains)/Losses Arising During the Year

$

 797.3 

 

$

 (635.2)

 

$

 55.9 

 

$

 (28.9)

 

 

 

 

 

 

Actuarial Losses Reclassified as Net Periodic Benefit Expense

 

 (122.8)

 

 

 (201.2)

 

 

 (5.6)

 

 

 (9.4)

 

 

 

 

 

 

Prior Service Cost Reclassified as Net Periodic Benefit Expense

 (4.2)

 

 

 (3.8)

 

 

 (0.2)

 

 

 (0.2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The following is a summary of the remaining Regulatory Assets and Accumulated Other Comprehensive Loss amounts that have not been recognized as components of net periodic benefit expense as of December 31, 2014 and 2013, and the amounts that are expected to be recognized as components in 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Regulatory Assets as of

 

 

Expected

 

 

AOCI as of

 

Expected

 

 

December 31,

 

 

2015 

 

December 31,

 

2015 

(Millions of Dollars)

2014 

 

2013 

 

Expense

 

2014 

 

2013 

 

Expense

Actuarial Loss

$

 1,811.9 

 

$

 1,137.4 

 

$

 149.1 

 

$

 93.5 

 

$

 43.2 

 

$

 6.4 

Prior Service Cost

 

 13.2 

 

 

 17.4 

 

 

 3.5 

 

 

 0.8 

 

 

 1.0 

 

 

 0.2 


PBOP Plans: As of December 31, 2013, the funded status of the NSTAR PBOP Plan was recorded on the NSTAR Electric & Gas balance sheet. As of December 31, 2013, all NSTAR employees were employed by NSTAR Electric & Gas. On January 1, 2014, concurrent with the service company merger, the PBOP assets and liabilities were attributed by participant and transferred to the applicable company's balance sheets. This change had no impact on the income statement or net assets of NSTAR Electric or NU.   For the year ended December 31, 2014, the NUSCO and NSTAR PBOP Plans are accounted for under the multiple-employer approach, with each company's balance sheet reflecting its share of the funded status of the plans.  


NU annually funds postretirement costs through tax deductible contributions to external trusts.


The following tables provide information on PBOP Plan benefit obligations, fair values of plan assets, and funded status:


 

 

PBOP

NU

As of December 31,

(Millions of Dollars)

2014 

 

2013 

Change in Benefit Obligation

 

 

 

 

 

Benefit Obligation as of Beginning of Year

$

 (1,038.0)

 

$

 (1,233.3)

Service Cost

 

 (12.5)

 

 

 (16.9)

Interest Cost

 

 (49.5)

 

 

 (47.2)

Actuarial Gain/(Loss)

 

 (95.5)

 

 

 200.9 

Benefits Paid

 

 47.6 

 

 

 58.5 

Benefit Obligation as of End of Year

$

 (1,147.9)

 

$

 (1,038.0)

Change in PBOP Plan Assets

 

 

 

 

 

Fair Value of Plan Assets as of Beginning of Year

$

 826.5 

 

$

 709.1 

Actual Return on Plan Assets

 

 43.7 

 

 

 118.3 

Employer Contributions

 

 40.0 

 

 

 57.6 

Benefits Paid

 

 (47.6)

 

 

 (58.5)

Fair Value of Plan Assets as of End of Year

$

 862.6 

 

$

 826.5 

Funded Status as of December 31st

$

 (285.3)

 

$

 (211.5)


 

 

PBOP

 

 

As of December 31,

 

 

2014 

 

2013 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Millions of Dollars)

CL&P

 

Electric

 

PSNH

 

WMECO

 

 

CL&P

 

PSNH

 

WMECO

Change in Benefit Obligation

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Benefit Obligation as of Beginning of Year

$

 (180.4)

 

$

 -  

 

$

 (93.5)

 

$

 (38.7)

 

 

$

 (196.8)

 

$

 (100.2)

 

$

 (42.5)

Decrease/(Increase) due to transfer of employees

 

 3.7 

 

 

 (395.5)

 

 

 4.3 

 

 

 1.0 

 

 

 

 -  

 

 

 -  

 

 

 -  

Service Cost

 

 (2.2)

 

 

 (3.1)

 

 

 (1.3)

 

 

 (0.4)

 

 

 

 (3.4)

 

 

 (2.3)

 

 

 (0.7)

Interest Cost

 

 (8.1)

 

 

 (19.4)

 

 

 (4.3)

 

 

 (1.7)

 

 

 

 (7.9)

 

 

 (4.0)

 

 

 (1.7)

Actuarial Gain/(Loss)

 

 3.5 

 

 

 (68.6)

 

 

 (1.1)

 

 

 1.3 

 

 

 

 13.3 

 

 

 7.2 

 

 

 3.3 

Benefits Paid

 

 9.6 

 

 

 17.9 

 

 

 4.1 

 

 

 1.9 

 

 

 

 14.4 

 

 

 5.8 

 

 

 2.9 

Benefit Obligation as of End of Year

$

 (173.9)

 

$

 (468.7)

 

$

 (91.8)

 

$

 (36.6)

 

 

$

 (180.4)

 

$

 (93.5)

 

$

 (38.7)

Change in PBOP Plan Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fair Value of Plan Assets as of Beginning of Year

$

 151.3 

 

$

 -  

 

$

 81.8 

 

$

 35.3 

 

 

$

 132.2 

 

$

 69.5 

 

$

 31.0 

(Decrease)/Increase due to transfer of employees

 

 (3.2)

 

 

 316.7 

 

 

 (3.1)

 

 

 (1.0)

 

 

 

 -  

 

 

 -  

 

 

 -  

Actual Return on Plan Assets

 

 6.3 

 

 

 18.4 

 

 

 3.8 

 

 

 1.6 

 

 

 

 24.8 

 

 

 13.4 

 

 

 6.0 

Employer Contributions

 

 4.2 

 

 

 19.3 

 

 

 2.5 

 

 

 0.4 

 

 

 

 8.7 

 

 

 4.7 

 

 

 1.2 

Benefits Paid

 

 (9.6)

 

 

 (17.9)

 

 

 (4.1)

 

 

 (1.9)

 

 

 

 (14.4)

 

 

 (5.8)

 

 

 (2.9)

Fair Value of Plan Assets as of End of Year

$

 149.0 

 

$

 336.5 

 

$

 80.9 

 

$

 34.4 

 

 

$

 151.3 

 

$

 81.8 

 

$

 35.3 

Funded Status as of December 31st

$

 (24.9)

 

$

 (132.2)

 

$

 (10.9)

 

$

 (2.2)

 

 

$

 (29.1)

 

$

 (11.7)

 

$

 (3.4)


During 2014, the Society of Actuaries released a series of updated mortality tables resulting from recent studies that measured mortality rates for various groups of individuals.  The updated mortality tables released in 2014 increased life expectancy of plan participants by 3 to 5 years and have the effect of increasing the estimate of benefits to be provided to plan participants.  The impact of this adoption on NU's funded status liability for the



114


year ended December 31, 2014 was an increase of approximately $82 million.  In addition, the decreases in the discount rates resulted in an increase on NU's funded status liability of approximately $110 million.  Partially offsetting these increases are the impact of other actuarial assumptions.


The following actuarial assumptions were used in calculating the PBOP Plans' year end funded status:

 

 

 

 

 

 

 

 

 

 

 

 

 

PBOP

 

 

 

As of December 31,

 

 

2014 

 

2013 

 

Discount Rate

 4.22 

%

 

 4.78 

%

-

 5.10 

%

 

Health Care Cost Trend Rate

 6.50 

%

 

7.00  %

 


PBOP Expense:  NU charges net periodic postretirement benefits expense to its subsidiaries based on the actual participant demographic data for each subsidiary's participants.  Benefit payments to participants and contributions are also tracked for each subsidiary.  The actual investment return in the trust each year is allocated to each of the subsidiaries annually in proportion to the investment return expected to be earned during the year.  For the years ended December 31, 2013 and 2012 (prior to the service company merger), the net periodic postretirement expense of the NSTAR PBOP Plan allocated to NSTAR Electric was $4.6 million and $34.1 million, respectively.  


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


 

 

PBOP

 

 

For the Year Ended December 31, 2014

 

 

 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

(Millions of Dollars)

NU

 

CL&P

 

Electric

 

PSNH

 

WMECO

Service Cost

$

 12.5 

 

$

 2.2 

 

$

 3.1 

 

$

 1.3 

 

$

 0.4 

Interest Cost

 

 49.5 

 

 

 8.1 

 

 

 19.4 

 

 

 4.3 

 

 

 1.7 

Expected Return on Plan Assets

 

 (63.3)

 

 

 (10.5)

 

 

 (25.9)

 

 

 (5.4)

 

 

 (2.3)

Actuarial Loss/(Gain)

 

 12.2 

 

 

 4.2 

 

 

 (0.5)

 

 

 2.2 

 

 

 0.5 

Prior Service Credit

 

 (2.8)

 

 

 - 

 

 

 (1.9)

 

 

 - 

 

 

 - 

Total Net Periodic Benefit Expense/(Income)

$

 8.1 

 

$

 4.0 

 

$

 (5.8)

 

$

 2.4 

 

$

 0.3 

Intercompany Allocations

 

N/A

 

$

 3.8 

 

$

 0.8 

 

$

 1.0 

 

$

 0.7 

Capitalized PBOP Expense/(Income)

$

 1.4 

 

$

 1.8 

 

$

 (2.3)

 

$

 0.8 

 

$

 0.2 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

PBOP

 

 

 

 

 

For the Year Ended December 31, 2013

 

 

 

(Millions of Dollars)

NU

 

CL&P

 

PSNH

 

WMECO

 

 

 

Service Cost

$

 16.9 

 

$

 3.4 

 

$

 2.3 

 

$

 0.7 

 

 

 

Interest Cost

 

 47.2 

 

 

 7.9 

 

 

 4.0 

 

 

 1.7 

 

 

 

Expected Return on Plan Assets

 

 (55.4)

 

 

 (10.1)

 

 

 (5.2)

 

 

 (2.3)

 

 

 

Actuarial Loss

 

 26.0 

 

 

 7.4 

 

 

 3.6 

 

 

 1.1 

 

 

 

Prior Service Credit

 

 (2.1)

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 

Total Net Periodic Benefit Expense

$

 32.6 

 

$

 8.6 

 

$

 4.7 

 

$

 1.2 

 

 

 

Intercompany Allocations

 

N/A

 

$

 7.1 

 

$

 1.6 

 

$

 1.3 

 

 

 

Capitalized PBOP Expense

$

 8.8 

 

$

 3.9 

 

$

 1.3 

 

$

 0.6 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 


 

PBOP

 

 

 

 

 

For the Year Ended December 31, 2012

 

 

 

(Millions of Dollars)

NU (1)

 

CL&P

 

PSNH

 

WMECO

 

 

 

Service Cost

$

 15.7 

 

$

 3.0 

 

$

 2.0 

 

$

 0.6 

 

 

 

Interest Cost

 

 49.0 

 

 

 9.2 

 

 

 4.6 

 

 

 2.0 

 

 

 

Expected Return on Plan Assets

 

 (39.2)

 

 

 (9.1)

 

 

 (4.6)

 

 

 (2.1)

 

 

 

Actuarial Loss

 

 36.0 

 

 

 7.5 

 

 

 3.6 

 

 

 1.2 

 

 

 

Prior Service Credit

 

 (1.4)

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 

Net Transition Obligation Cost

 

 12.2 

 

 

 6.1 

 

 

 2.5 

 

 

 1.3 

 

 

 

Total Net Periodic Benefit Expense

$

 72.3 

 

$

 16.7 

 

$

 8.1 

 

$

 3.0 

 

 

 

Intercompany Allocations

 

N/A

 

$

 7.9 

 

$

 2.0 

 

$

 1.5 

 

 

 

Capitalized PBOP Expense

$

 26.6 

 

$

 8.2 

 

$

 2.3 

 

$

 1.6 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1)

 NSTAR amounts were included in NU beginning April 10, 2012.

 

 




115



The following actuarial assumptions were used to calculate PBOP expense amounts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

PBOP

 

 

For the Years Ended December 31,

 

2014 

 

 

2013 

 

 

2012 

Discount Rate

 4.78 

%

-

 5.10 

%

 

 4.04 

%

-

 4.35 

%

 

 4.58 

%

-

 4.84 

%

Expected Long-Term Rate of Return

8.25  %

 

8.25  %

 

 7.30 

%

-

 8.25 

%


As of December 31, 2014 and 2013, the health care cost trend rate assumption used to determine the PBOP Plans' funded status was 6.5 percent and 7 percent, respectively, subsequently decreasing to an ultimate rate of 4.5 percent in 2023.  The health care cost trend rate assumption used to calculate the PBOP expense amounts was 7 percent for the year ended December 31, 2014.


Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans.  The effect of changing the assumed health care cost trend rate by one percentage point for the year ended December 31, 2014 would have the following effects:


 

One Percentage

 

One Percentage

(Millions of Dollars)

Point Increase

 

Point Decrease

Effect on PBOP Obligation

$

 111.2 

 

$

 (88.4)

Effect on Total Service and Interest Cost Components

 

 5.3 

 

 

 (4.4)


The following is a summary of the changes in plan assets and benefit obligations recognized in Regulatory Assets and OCI as well as amounts in Regulatory Assets and OCI reclassified as net periodic benefit (expense)/income during the years presented:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Amounts Reclassified To/From

 

 

 

 

 

 

 

Regulatory Assets

 

OCI

 

 

 

 

 

 

 

For the Years Ended December 31,

 

 

 

 

 

 

(Millions of Dollars)

2014 

 

2013 

 

2014 

 

2013 

 

 

 

 

 

 

Actuarial Losses/(Gains) Arising During the Year

$

 115.1 

 

$

(262.0)

 

$

 0.4 

 

$

 (1.9)

 

 

 

 

 

 

Actuarial Losses Reclassified as Net Periodic Benefit Expense

 

 (11.6)

 

 

 (24.9)

 

 

 (0.6)

 

 

 (1.1)

 

 

 

 

 

 

Prior Service Credit Reclassified as Net Periodic Benefit Income

 

 2.8 

 

 

 2.1 

 

 

 -  

 

 

 -  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The following is a summary of the remaining Regulatory Assets and Accumulated Other Comprehensive Loss amounts that have not been recognized as components of net periodic benefit expense as of December 31, 2014 and 2013, and the amounts that are expected to be recognized as components in 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Regulatory Assets as of

 

Expected

 

 

AOCI as of

 

Expected

 

December 31,

 

2015 

 

 

December 31,

 

2015 

(Millions of Dollars)

2014 

 

2013 

 

Expense

 

2014 

 

2013 

 

Expense

Actuarial Loss

$

 192.7 

 

$

 89.2 

 

$

6.9 

 

$

 6.0 

 

$

 6.2 

 

$

 0.3 

Prior Service Credit

 

 (1.8)

 

 

 (4.6)

 

 

 (0.5)

 

 

 -  

 

 

 -  

 

 

 -  


Estimated Future Benefit Payments:  The following benefit payments, which reflect expected future service, are expected to be paid by the Pension, SERP and PBOP Plans:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Millions of Dollars)

2015 

 

2016 

 

 

2017 

2018 

 

2019 

 

2020-2024

 

Pension and SERP

$

 244.5 

 

$

 253.6 

 

$

 268.9 

 

$

 273.4 

 

$

 285.4 

 

$

 1,591.1 

 

PBOP

 

 58.7 

 

 

 59.7 

 

 

 60.6 

 

 

 61.3 

 

 

 62.0 

 

 

 318.8 

 


Contributions:  NU contributed $171.6 million to the Pension Plans in 2014, of which $101 million was contributed by NSTAR Electric.  Based on the current status of the Pension Plans, NU expects to make contributions of approximately $155 million in 2015, of which $5 million will be contributed by NSTAR Electric and $1 million will be contributed by PSNH.  The remaining $149 million is expected to be contributed by other NU subsidiaries, primarily NUSCO.


NU contributed $40 million to the PBOP Plans in 2014 and expects to make approximately $27 million in contributions in 2015.  This amount will be funded into the 401(h) account and VEBAs up to the maximum tax-deductible level permitted.




116


Fair Value of Pension and PBOP Plan Assets:  Pension and PBOP funds are held in external trusts.  Trust assets, including accumulated earnings, must be used exclusively for Pension and PBOP payments.  NU's investment strategy for its Pension and PBOP Plans is to maximize the long-term rates of return on these plans' assets within an acceptable level of risk.  The investment strategy for each asset category includes a diversification of asset types, fund strategies and fund managers and establishes target asset allocations that are routinely reviewed and periodically rebalanced.  PBOP assets are comprised of assets held in the PBOP Plans as well as specific assets within the defined benefit pension plan trust (401(h) assets).  The investment policy and strategy of the 401(h) assets is consistent with those of the defined benefit pension plans.  NU's expected long-term rates of return on Pension and PBOP Plan assets are based on target asset allocation assumptions and related expected long-term rates of return.  In developing its expected long-term rate of return assumptions for the Pension and PBOP Plans, NU evaluated input from consultants, as well as long-term inflation assumptions and historical returns.  For the year ended December 31, 2014, management has assumed long-term rates of return of 8.25 percent for the Pension and PBOP Plan assets.  These long-term rates of return are based on the assumed rates of return for the target asset allocations as follows:


 

 

As of December 31, 2014 and 2013

 

 

 Pension and Tax-Exempt PBOP Plans

 

 

Target Asset Allocation

 

Assumed Rate of Return

Equity Securities:

 

 

 

 

United States

24%

 

9%

 

International

10%

 

9%

 

Emerging Markets

6%

 

10%

 

Private Equity

10%

 

13%

Debt Securities:

 

 

 

 

Fixed Income

15%

 

5%

 

High Yield Fixed Income

9%

 

7.5%

 

Emerging Markets Debt

6%

 

7.5%

Real Estate and Other Assets

9%

 

7.5%

Hedge Funds

11%

 

7%


The Taxable PBOP Plans have a target asset allocation of 70 percent equity securities and 30 percent fixed income securities.


The following table presents, by asset category, the Pension and PBOP Plan assets recorded at fair value on a recurring basis by the level in which they are classified within the fair value hierarchy:  


 

  

NU Pension Plans

 

  

Fair Value Measurements as of December 31,

(Millions of Dollars)

2014 

 

2013 

Asset Category:

Level 1

 

Level 2

 

Level 3

 

Total

 

Level 1

 

Level 2

 

Level 3

 

Total

Equity Securities (1)

$

 414.7 

 

$

 1,035.0 

 

$

 292.2 

 

$

 1,741.9 

 

$

326.8 

 

$

 1,172.1 

 

$

255.5 

 

$

 1,754.4 

Private Equity  

 

 18.8 

 

 

 -  

 

 

 367.9 

 

 

 386.7 

 

 

 96.4 

 

 

 -  

 

 

 300.3 

 

 

 396.7 

Fixed Income (2)

 

 10.2 

 

 

 561.4 

 

 

 722.0 

 

 

 1,293.6 

 

 

 11.6 

 

 

 605.1 

 

 

 589.5 

 

 

 1,206.2 

Real Estate and Other Assets

 

 -  

 

 

 132.0 

 

 

 265.8 

 

 

 397.8 

 

 

 -  

 

 

 88.2 

 

 

 288.5 

 

 

 376.7 

Hedge Funds

 

 -  

 

 

 20.0 

 

 

 475.0 

 

 

 495.0 

 

 

 -  

 

 

 -  

 

 

 416.9 

 

 

 416.9 

Total Master Trust Assets

$

 443.7 

 

$

 1,748.4 

 

$

 2,122.9 

 

$

 4,315.0 

 

$

 434.8 

 

$

 1,865.4 

 

$

 1,850.7 

 

$

 4,150.9 

 

Less:  401(h) PBOP Assets (3)

 

 

 

 

 

 

 

 

 

 

 (188.5)

 

 

 

 

 

 

 

 

 

 

 

 (165.0)

Total Pension Assets

 

 

 

 

 

 

 

 

 

$

 4,126.5 

 

 

 

 

 

 

 

 

 

 

$

 3,985.9 

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

 

  

NU PBOP Plans

 

  

Fair Value Measurements as of December 31,

(Millions of Dollars)

2014 

 

2013 

Asset Category:

Level 1

 

Level 2

 

Level 3

 

Total

 

Level 1

 

Level 2

 

Level 3

 

Total

Cash and Cash Equivalents

$

 -  

 

$

 -  

 

$

 -  

 

$

 -  

 

$

 11.1 

 

$

 -  

 

$

 -  

 

$

 11.1 

Equity Securities (1)

 

 104.1 

 

 

 172.8 

 

 

 75.1 

 

 

 352.0 

 

 

 110.3 

 

 

 176.8 

 

 

 69.1 

 

 

 356.2 

Private Equity

 

 -  

 

 

 -  

 

 

 24.9 

 

 

 24.9 

 

 

 -  

 

 

 -  

 

 

 17.9 

 

 

 17.9 

Fixed Income (2)

 

 16.1 

 

 

 110.0 

 

 

 78.3 

 

 

 204.4 

 

 

 -  

 

 

 119.7 

 

 

 51.5 

 

 

 171.2 

Real Estate and Other Assets

 

 

 

 

 19.4 

 

 

 15.0 

 

 

 34.4 

 

 

 -  

 

 

 14.2 

 

 

 33.9 

 

 

 48.1 

Hedge Funds

 

 

 

 

 -  

 

 

 58.4 

 

 

 58.4 

 

 

 -  

 

 

 -  

 

 

 57.0 

 

 

 57.0 

Total

$

 120.2 

 

$

 302.2 

 

$

 251.7 

 

$

 674.1 

 

$

 121.4 

 

$

 310.7 

 

$

 229.4 

 

$

 661.5 

 

Add:  401(h) PBOP Assets (3)

 

 

 

 

 

 

 

 

 

 

 188.5 

 

 

 

 

 

 

 

 

 

 

 

 165.0 

Total PBOP Assets

 

 

 

 

 

 

 

 

 

$

 862.6 

 

 

 

 

 

 

 

 

 

 

$

 826.5 


(1)

United States, International and Emerging Markets equity securities classified as Level 2 include investments in commingled funds.  Level 3 investments include hedge funds that are overlayed with equity index swaps and futures contracts and funds invested in equities that have redemption restrictions.  

(2)

Fixed Income investments classified as Level 3 investments include fixed income funds that invest in a variety of opportunistic fixed income strategies, and hedge funds that are overlayed with fixed income futures.  

(3)

The assets of the Pension Plans include a 401(h) account that has been allocated to provide health and welfare postretirement benefits under the PBOP Plans.


Effective January 1, 2013, the NSTAR Pension Plan assets were transferred into the NUSCO Pension Plan master trust.  The NUSCO Pension Plan is entitled to approximately 66 percent of each asset category in the master trust, the NSTAR Pension Plan is entitled to approximately 30 percent of each asset category in the master trust and the 401(h) plans are entitled to approximately four percent of each asset category in the master trust.  For the years ended December 31, 2014 and 2013 the NUSCO Pension Plan was entitled to $2,803.6 million and $2,750.4 million respectively and the NSTAR Pension Plan was entitled to $1,322.9 million and $1,235.3 million, respectively.  Also effective January 1, 2013, the NSTAR PBOP Plan



117


assets were transferred into a master trust with the NUSCO PBOP Plan assets and assets were allocated to each plan.  For the years ended December 31, 2014 and 2013, the NUSCO PBOP Plan was entitled to $399 million and $391 million, respectively, and the NSTAR PBOP Plan was entitled to $463.6 million and $435.5 million, respectively.  CL&P, PSNH and WMECO are allocated a portion of the NUSCO Pension and PBOP Plan assets.  NSTAR Electric is entitled to a portion of the NSTAR Pension and PBOP Plan assets.


The Company values assets based on observable inputs when available.  Equity securities, exchange traded funds and futures contracts classified as Level 1 in the fair value hierarchy are priced based on the closing price on the primary exchange as of the balance sheet date.  Commingled funds included in Level 2 equity securities are recorded at the net asset value provided by the asset manager, which is based on the market prices of the underlying equity securities.  Swaps are valued using pricing models that incorporate interest rates and equity and fixed income index closing prices to determine a net present value of the cash flows.  Fixed income securities, such as government issued securities, corporate bonds and high yield bond funds, are included in Level 2 and are valued using pricing models, quoted prices of securities with similar characteristics or discounted cash flows.  The pricing models utilize observable inputs such as recent trades for the same or similar instruments, yield curves, discount margins and bond structures.  Hedge funds and investments in opportunistic fixed income funds are recorded at net asset value based on the values of the underlying assets.  The assets in the hedge funds and opportunistic fixed income funds are valued using observable inputs and are classified as Level 3 within the fair value hierarchy due to redemption restrictions.  Private Equity investments and Real Estate and Other Assets are valued using the net asset value provided by the partnerships, which are based on discounted cash flows of the underlying investments, real estate appraisals or public market comparables of the underlying investments.  These investments are classified as Level 3 due to redemption restrictions.  


Fair Value Measurements Using Significant Unobservable Inputs (Level 3):  The following tables present changes in the Level 3 category of Pension and PBOP Plan assets for the years ended December 31, 2014 and 2013:  


 

 

NU Pension Plans

 

 

Equity

 

Private

 

Fixed

 

Real Estate and

 

Hedge

 

 

(Millions of Dollars)

Securities

 

Equity

 

Income

 

Other Assets

 

Funds

 

Total

Balance as of January 1, 2013

$

 322.7 

 

$

 267.9 

 

$

 315.1 

 

$

 235.4 

 

$

 418.9 

 

$

 1,560.0 

Transfer Between Categories

 

 -  

 

 

 -  

 

 

 32.5 

 

 

 -  

 

 

 (32.5)

 

 

 -  

Actual Return/(Loss) on Plan Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Relating to Assets Still Held as of Year End

 

 20.6 

 

 

 15.4 

 

 

 55.3 

 

 

 12.9 

 

 

 33.4 

 

 

 137.6 

 

Relating to Assets Distributed During the Year

 

 12.2 

 

 

 13.7 

 

 

 (1.0)

 

 

 6.2 

 

 

 -  

 

 

 31.1 

Purchases, Sales and Settlements

 

 (100.0)

 

 

 3.3 

 

 

 187.6 

 

 

 34.0 

 

 

 (2.9)

 

 

 122.0 

Balance as of December 31, 2013

$

 255.5 

 

$

 300.3 

 

$

 589.5 

 

$

 288.5 

 

$

 416.9 

 

$

 1,850.7 

Actual Return/(Loss) on Plan Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Relating to Assets Still Held as of Year End

 

 (2.3)

 

 

 14.0 

 

 

 45.2 

 

 

 (3.6)

 

 

 23.5 

 

 

 76.8 

 

Relating to Assets Distributed During the Year

 

 -  

 

 

 13.9 

 

 

 (6.2)

 

 

 28.3 

 

 

 (15.2)

 

 

 20.8 

Purchases, Sales and Settlements

 

 39.0 

 

 

 39.7 

 

 

 93.5 

 

 

 (47.4)

 

 

 49.8 

 

 

 174.6 

Balance as of December 31, 2014

$

 292.2 

 

$

 367.9 

 

$

 722.0 

 

$

 265.8 

 

$

 475.0 

 

$

 2,122.9 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NU PBOP Plans

 

 

Equity

 

Private

 

Fixed

 

Real Estate and

 

Hedge

 

 

(Millions of Dollars)

Securities

 

Equity

 

Income

 

Other Assets

 

Funds

 

Total

Balance as of January 1, 2013

$

 36.3 

 

$

 11.3 

 

$

 32.1 

 

$

 26.7 

 

$

 39.6 

 

$

 146.0 

Actual Return/(Loss) on Plan Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Relating to Assets Still Held as of Year End

 

 20.8 

 

 

 1.5 

 

 

 4.1 

 

 

 3.9 

 

 

 5.4 

 

 

 35.7 

 

Relating to Assets Distributed During the Year

 

 -  

 

 

 0.2 

 

 

 -  

 

 

 (0.1)

 

 

 -  

 

 

 0.1 

Purchases, Sales and Settlements

 

 12.0 

 

 

 4.9 

 

 

 15.3 

 

 

 3.4 

 

 

 12.0 

 

 

 47.6 

Balance as of December 31, 2013

$

 69.1 

 

$

 17.9 

 

$

 51.5 

 

$

 33.9 

 

$

 57.0 

 

$

 229.4 

Actual Return/(Loss) on Plan Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Relating to Assets Still Held as of Year End

 

 6.0 

 

 

 1.3 

 

 

 1.9 

 

 

 (2.8)

 

 

 1.4 

 

 

 7.8 

 

Relating to Assets Distributed During the Year

 

 -  

 

 

 0.1 

 

 

 -  

 

 

 (2.2)

 

 

 -   

 

 

 (2.1)

Purchases, Sales and Settlements

 

 -  

 

 

 5.6 

 

 

 24.9 

 

 

 (13.9)

 

 

 -  

 

 

 16.6 

Balance as of December 31, 2014

$

 75.1 

 

$

 24.9 

 

$

 78.3 

 

$

 15.0 

 

$

 58.4 

 

$

 251.7 


B.

Defined Contribution Plans

Effective January 1, 2014, NU maintains one defined contribution plan on behalf of eligible participants, the NUSCO 401k Plan.  The NUSCO 401k Plan provides for employee and employer contributions up to statutory limits.  For eligible employees, the NUSCO 401k Plan provides employer matching contributions of either 100 percent up to a maximum of three percent of eligible compensation or 50 percent up to a maximum of eight percent of eligible compensation.  For newly hired employees beginning in 2014, the NUSCO 401k Plan provides employer matching contributions of 100 percent up to a maximum of three percent of eligible compensation.


The NUSCO 401k Plan also contains a K-Vantage feature on behalf of eligible participants, which provides an additional employer contribution based on age and years of service.  K-Vantage participants are not eligible to actively participate in the NU defined benefit plans.




118


The total defined contribution plan employer matching contributions, including the K-Vantage program contributions, were as follows:


 

 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

(Millions of Dollars)

NU (1)

 

CL&P

 

Electric

 

PSNH

 

WMECO

2014 

$

29.7 

 

$

5.0 

 

$

6.3 

 

$

3.2 

 

$

1.0 

2013 

 

37.0 

 

 

5.1 

 

 

8.5 

 

 

3.3 

 

 

1.0 

2012 

 

25.7 

 

 

4.8 

 

 

9.0 

 

 

3.3 

 

 

0.9 


(1)

NSTAR amounts were included in NU beginning April 10, 2012.  


Allocations of NU common shares were made from NU treasury shares to satisfy the NUSCO 401k Plan obligation to provide 100 percent of the matching contribution in NU common shares.  For treasury shares used to satisfy the NUSCO 401k Plan employer matching contributions, compensation expense is recognized equal to the fair value of shares that have been allocated to participants.  Any difference between the fair value and the average cost of the allocated treasury shares is charged or credited to Capital Surplus, Paid In.  For the years ended December 31, 2014, 2013 and 2012, NU recognized $22 million, $9.1 million and $8.9 million, respectively, of compensation expense related to treasury shares used to satisfy the matching contribution.


C.

Share-Based Payments

Share-based compensation awards are recorded using a fair-value-based method at the date of grant.  NU, CL&P, NSTAR Electric, PSNH and WMECO record compensation expense related to these awards, as applicable, for shares issued or sold to their respective employees and officers, as well as the allocation of costs associated with shares issued or sold to NU's service company employees and officers that support CL&P, NSTAR Electric, PSNH and WMECO.  


Upon consummation of the merger with NSTAR, the NSTAR 1997 Share Incentive Plan and the NSTAR 2007 Long-Term Incentive Plan were assumed by NU.  Share-based awards granted under the NSTAR Plans and held by NSTAR employees and officers were generally converted into outstanding NU share-based compensation awards with an estimated fair value of $53.2 million.  Refer to Note 21, "Merger of NU and NSTAR," for further information regarding the merger transaction.  Specifically, as of the merger closing, and as adjusted by the exchange ratio, NU converted (1) outstanding NSTAR stock options into 2,664,894 NU stock options valued at $30.5 million, (2) NSTAR deferred shares and NSTAR performance shares into 421,775 NU RSU's valued at $15.5 million, and (3) NSTAR RSU retention awards into 195,619 NU RSU retention awards valued at $7.2 million.


NU Incentive Plans:  NU maintains long-term equity-based incentive plans in which NU, CL&P, NSTAR Electric, PSNH and WMECO employees, officers and board members are eligible to participate.  The incentive plans authorize NU to grant up to 8,000,000 new shares for various types of awards, including RSUs and performance shares, to eligible employees, officers, and board members.  As of December 31, 2014 and 2013, NU had 3,112,020 and 3,440,590 common shares, respectively, available for issuance under these plans.  NU also maintains an ESPP for eligible employees.  


NU accounts for its various share-based plans as follows:


·

RSUs - NU records compensation expense, net of estimated forfeitures, on a straight-line basis over the requisite service period based upon the fair value of NU's common shares at the date of grant.  The par value of RSUs is reclassified to Common Stock from APIC as RSUs become issued as common shares.


·

Performance Shares - NU records compensation expense, net of estimated forfeitures, on a straight-line basis over the requisite service period.  Performance shares vest based upon the extent to which Company goals are achieved.  Vesting of outstanding performance shares is based upon both the Company's EPS growth over the requisite service period and the total shareholder return as compared to the Edison Electric Institute (EEI) Index during the requisite service period.  The fair value of performance shares is determined at the date of grant using a lattice model.


·

Stock Options - Stock options issued under the NSTAR Incentive Plan that were outstanding immediately prior to the completion of the merger with NSTAR converted into fully vested options to acquire NU common shares, as adjusted by the exchange ratio.  The fair value of these awards on the merger date was included in the purchase price as it represented consideration transferred in the merger.  Accordingly, no compensation expense was recorded for these stock options.  


·

ESPP Shares - For shares sold under the ESPP, no compensation expense was recorded as the ESPP qualifies as a non-compensatory plan.  




119


RSUs:  NU granted RSUs under the annual long-term incentive programs that are subject to three-year graded vesting schedules for employees, and one-year graded vesting schedules, or immediate vesting, for board members.  RSUs are paid in shares, reduced by amounts sufficient to satisfy withholdings for income taxes, subsequent to vesting.  A summary of RSU transactions is as follows:


 

 

 

 

Weighted Average

 

 

RSUs

 

Grant-Date

 

 

(Units)

 

Fair Value

Outstanding as of January 1, 2012

 

 959,920 

 

$

 26.36 

Granted

 

 614,930 

 

$

 33.04 

Converted NSTAR Awards upon Merger

 

 617,394 

 

$

 36.79 

Converted from NU Performance Shares upon Merger

 

 451,358 

 

$

 34.32 

Shares issued

 

 (363,779)

 

$

 29.05 

Forfeited

 

 (96,504)

 

$

 34.97 

Outstanding as of December 31, 2012

 

 2,183,319 

 

$

 31.99 

Granted

 

 373,939 

 

$

 39.56 

Shares issued

 

 (891,129)

 

$

 32.15 

Forfeited

 

 (29,689)

 

$

 33.75 

Outstanding as of December 31, 2013

 

 1,636,440 

 

$

 33.61 

Granted

 

 338,576 

 

$

 42.27 

Shares issued

 

 (567,209)

 

$

 33.48 

Forfeited

 

 (27,060)

 

$

 39.62 

Outstanding as of December 31, 2014

 

 1,380,747 

 

$

 35.67 


As of December 31, 2014 and 2013, the number and weighted average grant-date fair value of unvested RSUs was 1,024,729 and $38.14 per share, and 1,162,216 and $36.58 per share, respectively.  The number and weighted average grant-date fair value of RSUs vested and either paid or deferred during 2014 was 437,887 and $37.36 per share, respectively.  As of December 31, 2014, 356,018 RSUs were fully vested and deferred and an additional 973,493 are expected to vest.  


Performance Shares:  NU granted performance shares under the annual long-term incentive programs that vest based upon the extent to which Company goals are achieved at the end of three-year performance measurement periods.  Performance shares are paid in shares, after the performance measurement period.  A summary of performance share transactions is as follows:


 

 

Performance

 

Weighted Average

 

 

Shares

 

Grant-Date

 

(Units)

 

Fair Value

Outstanding as of January 1, 2012

 

 483,133 

 

$

 29.18 

Granted

 

 225,935 

 

$

 35.09 

Converted to RSUs upon Merger

 

 (451,358)

 

$

 34.32 

Shares issued

 

 (106,773)

 

$

 24.52 

Outstanding as of December 31, 2012

 

 150,937 

 

$

 25.04 

Granted

 

 191,961 

 

$

 40.96 

Shares issued

 

 (150,944)

 

$

 25.04 

Forfeited

 

 (1,526)

 

$

 40.93 

Outstanding as of December 31, 2013

 

 190,428 

 

$

 40.96 

Granted

 

 193,396 

 

$

 43.40 

Shares issued

 

 (2,009)

 

$

 41.46 

Forfeited

 

 (6,171)

 

$

 42.02 

Outstanding as of December 31, 2014

 

 375,644 

 

$

 42.20 


Upon closing of the merger with NSTAR, 451,358 performance shares under the NU 2011 and 2012 Long-Term Incentive Programs converted to RSUs according to the terms of these programs.  Performance shares under the NU 2010 Incentive Program were measured based upon a modified performance period through the date of the merger, in accordance with the terms of the program, and were fully distributed in 2013.  


The total compensation expense and associated future income tax benefit recognized by NU, CL&P, NSTAR Electric, PSNH and WMECO for share-based compensation awards are as follows:


NU

 

For the Years Ended December 31,

(Millions of Dollars)

2014 

 

2013 

 

2012 (1)

Compensation Expense

$

 24.6 

 

$

 27.0 

 

$

 25.8 

Future Income Tax Benefit

 

 10.3 

 

 

 10.7 

 

 

 10.2 


 

 

For the Years Ended December 31,

 

 

2014 

 

2013 

 

2012 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

(Millions of Dollars)

CL&P

 

Electric

 

PSNH

 

WMECO

 

CL&P

 

Electric

 

PSNH

 

WMECO

 

CL&P

 

Electric

 

PSNH

 

WMECO

Compensation Expense

$

8.1 

 

$

7.4 

 

$

3.0 

 

$

1.3 

 

$

6.8 

 

$

7.5 

 

$

2.3 

 

$

1.3 

 

$

4.8 

 

$

7.4 

 

$

1.8 

 

$

1.0 

Future Income Tax Benefit

3.4 

 

 

3.1 

 

 

1.3 

 

 

0.5 

 

 

2.7 

 

 

3.0 

 

 

0.9 

 

 

0.5 

 

 

1.9 

 

 

2.9 

 

 

0.7 

 

 

0.4 


(1)

NSTAR amounts were included in NU beginning April 10, 2012.  




120


As of December 31, 2014, there was $15.7 million of total unrecognized compensation expense related to nonvested share-based awards for NU, $6.1 million for CL&P, $4.3 million for NSTAR Electric, $2 million for PSNH and $1 million for WMECO.  This cost is expected to be recognized ratably over a weighted-average period of 1.65 years for NU, 1.68 years for CL&P, 1.69 years for NSTAR Electric, 1.71 years for PSNH and 1.68 years for WMECO.


For the years ended December 31, 2014 and 2012, additional tax benefits totaling $9.5 million and $8.5 million increased cash flows from financing activities.  For the year ended December 31, 2013, additional tax benefits totaling $5.5 million decreased cash flows from financing activities.


Stock Options:  Stock options were granted under the NU and NSTAR incentive plans.  Options currently outstanding expire ten years from the date of grant and are fully vested.  The weighted average remaining contractual lives for the options outstanding as of December 31, 2014 is 4.3 years.  A summary of stock option transactions is as follows:


 

 

 

 

 

Weighted Average

 

Intrinsic Value

 

 

 

Options

 

Exercise Price

 

(Millions)

Outstanding and Exercisable - January 1, 2012

 

 47,374 

 

$

 18.78 

 

 

 

Converted NSTAR Options upon Merger

 

 2,664,894 

 

$

 23.99 

 

 

 

Exercised

 

(1,166,511)

 

$

 22.53 

 

$

 18.7 

Outstanding and Exercisable - December 31, 2012

 

 1,545,757 

 

$

 24.92 

 

 

 

Exercised

 

(324,382)

 

$

 20.97 

 

$

 6.7 

Outstanding and Exercisable - December 31, 2013

 

 1,221,375 

 

$

 25.97 

 

 

 

Exercised

 

 (869,759)

 

$

 25.68 

 

$

 16.4 

Outstanding and Exercisable - December 31, 2014

 

 351,616 

 

$

 26.69 

 

$

 9.4 


Cash received for options exercised during the year ended December 31, 2014 totaled $22.3 million.  The tax benefit realized from stock options exercised totaled $6.6 million for the year ended December 31, 2014.  


Employee Share Purchase Plan:  NU maintains an ESPP for eligible employees, which allows for NU common shares to be purchased by employees at the end of successive six-month offering periods at 95 percent of the closing market price on the last day of each six-month period.  Employees are permitted to purchase shares having a value not exceeding 25 percent of their compensation as of the beginning of the offering period up to a specified limit.  The ESPP qualifies as a non-compensatory plan under accounting guidance for share-based payments, and no compensation expense is recorded for ESPP purchases.   


During 2014, employees purchased 40,779 shares at discounted prices of $41.61 and $41.71.  Employees purchased 39,526 shares in 2013 at discounted prices of $38.69 and $42.19.  As of December 31, 2014 and 2013, 776,975 and 817,754 shares, respectively, remained available for future issuance under the ESPP.


An income tax rate of 40 percent is used to estimate the tax effect on total share-based payments determined under the fair value-based method for all awards.  The Company generally settles stock option exercises and fully vested RSUs and performance shares with either the issuance of new common shares or the issuance of common shares purchased in the open market.


D.

Other Retirement Benefits

NU provides benefits for retirement and other benefits for certain current and past company officers of NU, including CL&P, PSNH and WMECO.  These benefits are accounted for on an accrual basis and expensed over the service lives of the employees.  The actuarially-determined liability for these benefits, which is included in Other Long-Term Liabilities on the balance sheets, as well as the related expense, are as follows:


 

 

 

 

 

 

 

 

 

 

 

 

NU

 

 

For the Years Ended December 31,

(Millions of Dollars)

2014 

 

2013 

 

2012 

Actuarially-Determined Liability

$

57.5 

 

$

51.3 

 

$

54.6 

Other Retirement Benefits Expense

 

4.5 

 

 

4.4 

 

 

4.7 


 

 

 

For the Years Ended December 31,

 

 

 

2014 

 

2013 

 

2012 

(Millions of Dollars)

CL&P

 

NSTAR Electric

 

PSNH

 

WMECO

 

CL&P

 

PSNH

 

WMECO

 

CL&P

 

PSNH

 

WMECO

Actuarially-Determined Liability

$

0.4 

 

$

 -   

 

$

2.6 

 

$

0.2 

 

$

0.4 

 

$

2.3 

 

$

0.1 

 

$

0.4 

 

$

2.5 

 

$

0.2 

Other Retirement Benefits Expense

 

2.1 

 

 

0.3 

 

 

0.9 

 

 

0.4 

 

 

2.5 

 

 

1.0 

 

 

0.5 

 

 

2.6 

 

 

1.0 

 

 

0.5 




121


10.

INCOME TAXES


The components of income tax expense are as follows:


NU

For the Years Ended December 31,

(Millions of Dollars)

2014 

 

2013 

 

2012 (1)

Current Income Taxes:

 

 

 

 

 

 

 

 

  Federal

$

4.4 

 

$

8.8 

 

$

(30.9)

  State

 

24.5 

 

 

(9.4)

 

 

17.6 

Total Current

 

28.9 

 

 

(0.6)

 

 

(13.3)

Deferred Income Taxes, Net:

 

 

 

 

 

 

 

 

  Federal

 

406.8 

 

 

386.2 

 

 

291.3 

  State

 

36.5 

 

 

45.4 

 

 

0.8 

Total Deferred

 

443.3 

 

 

431.6 

 

 

292.1 

Investment Tax Credits, Net

 

(3.9)

 

 

(4.1)

 

 

(3.9)

Income Tax Expense

$

468.3 

 

$

426.9 

 

$

274.9 

 

 

 

 

 

 

 

 

 

(1) NSTAR amounts were included in NU beginning April 10, 2012.


 

 

For the Years Ended December 31,

 

 

2014 

 

2013 

 

2012 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

(Millions of Dollars)

CL&P

 

Electric

 

PSNH

 

WMECO

 

CL&P

 

Electric

 

PSNH

 

WMECO

 

CL&P

 

Electric

 

PSNH

 

WMECO

Current Income Taxes:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Federal

$

 (0.2)

 

$

 75.0 

 

$

 (22.6)

 

$

 1.9 

 

$

 20.1 

 

$

 95.8 

 

$

 (8.2)

 

$

 (53.4)

 

$

 (47.8)

 

$

 93.5 

 

$

 (0.9)

 

$

 (24.7)

 

State

 

 4.3 

 

 

 20.2 

 

 

 (0.1)

 

 

 1.8 

 

 

 (6.7)

 

 

 29.6 

 

 

 3.6 

 

 

 4.2 

 

 

 3.1 

 

 

 27.6 

 

 

 3.4 

 

 

 3.4 

Total Current

 

 4.1 

 

 

 95.2 

 

 

 (22.7)

 

 

 3.7 

 

 

 13.4 

 

 

 125.4 

 

 

 (4.6)

 

 

 (49.2)

 

 

 (44.7)

 

 

 121.1 

 

 

 2.5 

 

 

 (21.3)

Deferred Income
   Taxes, Net:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Federal

 

 138.0 

 

 

 88.0 

 

 

 79.6 

 

 

 28.1 

 

 

 114.9 

 

 

 49.8 

 

 

 64.5 

 

 

 84.7 

 

 

 141.5 

 

 

 11.4 

 

 

 46.5 

 

 

 51.2 

 

State

 

 (7.1)

 

 

 20.1 

 

 

 15.2 

 

 

 6.0 

 

 

 15.1 

 

 

 (1.0)

 

 

 11.2 

 

 

 2.3 

 

 

 (0.5)

 

 

 (7.1)

 

 

 12.0 

 

 

 2.7 

Total Deferred

 

 130.9 

 

 

 108.1 

 

 

 94.8 

 

 

 34.1 

 

 

 130.0 

 

 

 48.8 

 

 

 75.7 

 

 

 87.0 

 

 

 141.0 

 

 

 4.3 

 

 

 58.5 

 

 

 53.9 

Investment Tax
   Credits, Net

 

 (1.5)

 

 

 (1.3)

 

 

 -  

 

 

 (0.5)

 

 

 (1.7)

 

 

 (1.3)

 

 

 -  

 

 

 (0.4)

 

 

 (1.9)

 

 

 (1.4)

 

 

 -  

 

 

 (0.5)

Income Tax Expense

$

 133.5 

 

$

 202.0 

 

$

 72.1 

 

$

 37.3 

 

$

 141.7 

 

$

 172.9 

 

$

 71.1 

 

$

 37.4 

 

$

 94.4 

 

$

 124.0 

 

$

 61.0 

 

$

 32.1 


A reconciliation between income tax expense and the expected tax expense at the statutory rate is as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

NU

For the Years Ended December 31,

 

(Millions of Dollars, except percentages)

2014 

 

 

2013 

 

 

2012 (1)

 

Income Before Income Tax Expense

$

 1,295.4 

 

 

$

 1,220.6 

 

 

$

 808.0 

 

 

 

 

 

 

 

 

 

 

 

 

 

Statutory Federal Income Tax Expense at 35%

 

 453.4 

 

 

 

 427.2 

 

 

 

 282.8 

 

Tax Effect of Differences:

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation

 

 (5.6)

 

 

 

 (7.4)

 

 

 

 (10.8)

 

 

Investment Tax Credit Amortization

 

 (3.9)

 

 

 

 (4.1)

 

 

 

 (3.9)

 

 

Other Federal Tax Credits

 

 (3.5)

 

 

 

 (3.7)

 

 

 

 (3.8)

 

 

State Income Taxes, Net of Federal Impact

 

 42.5 

 

 

 

 27.6 

 

 

 

 4.4 

 

 

Dividends on ESOP

 

 (8.0)

 

 

 

 (8.0)

 

 

 

 (6.4)

 

 

Tax Asset Valuation Allowance/Reserve Adjustments

 

 (2.9)

 

 

 

 (4.3)

 

 

 

 7.6 

 

 

Other, Net

 

 (3.7)

 

 

 

 (0.4)

 

 

 

 5.0 

 

Income Tax Expense

$

 468.3 

 

 

$

 426.9 

 

 

$

 274.9 

 

Effective Tax Rate

 

36.2%

 

 

 

35.0%

 

 

 

34.0%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1) NSTAR amounts were included in NU beginning April 10, 2012.

 




122






 

 

For the Years Ended December 31,

 

 

2014 

 

2013 

 

2012 

(Millions of Dollars,

 

 

 

NSTAR

 

 

 

 

 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

 

except percentages)

CL&P

 

Electric

 

PSNH

 

WMECO

 

CL&P

 

Electric

 

PSNH

 

WMECO

 

CL&P

 

Electric

 

PSNH

 

WMECO

Income Before Income
   Tax Expense

$

 421.2 

 

$

 505.1 

 

$

 186.1 

 

$

 95.1 

 

$

 421.1 

 

$

 441.4 

 

$

 182.5 

 

$

 97.8 

 

$

 304.2 

 

$

 314.2 

 

$

 157.9 

 

$

 86.6 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Statutory Federal Income
   Tax Expense at 35%

 

 147.4 

 

 

 176.8 

 

 

 65.1 

 

 

 33.3 

 

 

 147.4 

 

 

 154.5 

 

 

 63.9 

 

 

 34.2 

 

 

 106.5 

 

 

 110.0 

 

 

 55.3 

 

 

 30.3 

Tax Effect of Differences:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation

 

 (3.6)

 

 

 (1.3)

 

 

 0.3 

 

 

 (0.2)

 

 

 (7.0)

 

 

 0.1 

 

 

 0.6 

 

 

 -  

 

 

 (9.0)

 

 

 -  

 

 

 (0.3)

 

 

 0.2 

 

Investment Tax Credit
  Amortization

 

 (1.5)

 

 

 (1.3)

 

 

 -  

 

 

 (0.5)

 

 

 (1.7)

 

 

 (1.3)

 

 

 -  

 

 

 (0.4)

 

 

 (1.9)

 

 

 (1.4)

 

 

 -  

 

 

 (0.5)

 

Other Federal Tax Credits

 

 -  

 

 

 -  

 

 

 (3.5)

 

 

 -  

 

 

 -  

 

 

 -  

 

 

 (3.7)

 

 

 -  

 

 

 -  

 

 

 -  

 

 

 (3.8)

 

 

 -  

 

State Income Taxes,
  Net of Federal Impact

 

 4.4 

 

 

 26.2 

 

 

 9.8 

 

 

 5.0 

 

 

 5.0 

 

 

 18.6 

 

 

 9.6 

 

 

 4.2 

 

 

 0.1 

 

 

 13.4 

 

 

 10.0 

 

 

 4.0 

 

Tax Asset Valuation Allowance/
  Reserve Adjustments

 (6.3)

 

 

 -  

 

 

 -  

 

 

 -  

 

 

 0.4 

 

 

 -  

 

 

 -  

 

 

 -  

 

 

 1.6 

 

 

 -  

 

 

 -  

 

 

 -  

 

Other, Net

 

 (6.9)

 

 

 1.6 

 

 

 0.4 

 

 

 (0.3)

 

 

 (2.4)

 

 

 1.0 

 

 

 0.7 

 

 

 (0.6)

 

 

 (2.9)

 

 

 2.0 

 

 

 (0.2)

 

 

 (1.9)

Income Tax Expense

$

 133.5 

 

$

 202.0 

 

$

 72.1 

 

$

 37.3 

 

$

 141.7 

 

$

 172.9 

 

$

 71.1 

 

$

 37.4 

 

$

 94.4 

 

$

 124.0 

 

$

 61.0 

 

$

 32.1 

Effective Tax Rate

 

31.7%

 

 

40.0%

 

 

38.7%

 

 

39.2%

 

 

33.6%

 

 

39.2%

 

 

39.0%

 

 

38.2%

 

 

31.0%

 

 

39.5%

 

 

38.6%

 

 

37.1%


NU, CL&P, NSTAR Electric, PSNH and WMECO file a consolidated federal income tax return and unitary, combined and separate state income tax returns.  These entities are also parties to a tax allocation agreement under which taxable subsidiaries do not pay any more taxes than they would have otherwise paid had they filed a separate company tax return, and subsidiaries generating tax losses, if any, are paid for their losses when utilized.


Deferred tax assets and liabilities are recognized for the future tax effects of temporary differences between the carrying amounts and the tax basis of assets and liabilities.  The tax effect of temporary differences is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and relevant accounting authoritative literature.  The tax effects of temporary differences that give rise to the net accumulated deferred income tax obligations are as follows:


NU

As of December 31,

(Millions of Dollars)

2014 

 

2013 

Deferred Tax Assets:

 

 

 

 

 

 

Employee Benefits

$

 632.2 

 

$

 435.2 

 

Derivative Liabilities

 

 199.6 

 

 

 272.9 

 

Regulatory Deferrals - Liabilities

 

 366.7 

 

 

 272.7 

 

Allowance for Uncollectible Accounts

 

 60.5 

 

 

 65.0 

 

Tax Effect - Tax Regulatory Liabilities

 

 10.0 

 

 

 16.2 

 

Federal Net Operating Loss Carryforwards

 

 59.1 

 

 

 158.0 

 

Purchase Accounting Adjustment

 

 126.2 

 

 

 132.8 

 

Other

 

 198.7 

 

 

 230.6 

Total Deferred Tax Assets

 

 1,653.0 

 

 

 1,583.4 

 

Less:  Valuation Allowance

 

 5.1 

 

 

 24.3 

Net Deferred Tax Assets

$

 1,647.9 

 

$

 1,559.1 

Deferred Tax Liabilities:

 

 

 

 

 

 

Accelerated Depreciation and Other Plant-Related Differences

$

 4,215.9 

 

$

 3,806.5 

 

Property Tax Accruals

 

 109.6 

 

 

 95.1 

 

Regulatory Amounts:

 

 

 

 

 

 

 

Regulatory Deferrals - Assets

 

 1,277.9 

 

 

 1,146.7 

 

 

Tax Effect - Tax Regulatory Assets

 

 240.2 

 

 

 248.2 

 

 

Goodwill Regulatory Asset - 1999 Merger

 

 203.2 

 

 

 211.5 

 

 

Derivative Assets

 

 32.6 

 

 

 30.1 

 

 

Other

 

 196.3 

 

 

 157.1 

Total Deferred Tax Liabilities

$

 6,275.7 

 

$

 5,695.2 




123






 

 

 

As of December 31,

 

 

 

2014 

 

2013 

 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

(Millions of Dollars)

CL&P

 

Electric

 

PSNH

 

WMECO

 

CL&P

 

Electric

 

PSNH

 

WMECO

Deferred Tax Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Employee Benefits

$

 129.0 

 

$

 39.9 

 

$

 46.8 

 

$

 9.2 

 

$

 56.0 

 

$

 38.3 

 

$

 15.5 

 

$

 (1.8)

 

Derivative Liabilities

 

 193.0 

 

 

 1.8 

 

 

 -  

 

 

 -  

 

 

 272.4 

 

 

 3.3 

 

 

 -  

 

 

 (2.9)

 

Regulatory Deferrals - Liabilities

 

 73.9 

 

 

 181.3 

 

 

 46.5 

 

 

 11.4 

 

 

 61.5 

 

 

 114.7 

 

 

 40.9 

 

 

 1.0 

 

Allowance for Uncollectible Accounts

 

 32.3 

 

 

 13.8 

 

 

 3.2 

 

 

 3.8 

 

 

 31.2 

 

 

 15.4 

 

 

 3.1 

 

 

 3.3 

 

Tax Effect - Tax Regulatory Liabilities

 

 3.1 

 

 

 1.8 

 

 

 2.1 

 

 

 2.5 

 

 

 4.7 

 

 

 5.4 

 

 

 2.1 

 

 

 1.6 

 

Federal Net Operating Loss Carryforwards

 

 -  

 

 

 -  

 

 

 32.1 

 

 

 4.5 

 

 

 51.0 

 

 

 -  

 

 

 56.6 

 

 

 18.6 

 

Other

 

 53.8 

 

 

 19.9 

 

 

 48.9 

 

 

 4.9 

 

 

 75.3 

 

 

 31.3 

 

 

 40.3 

 

 

 8.3 

Total Deferred Tax Assets

 

 485.1 

 

 

 258.5 

 

 

 179.6 

 

 

 36.3 

 

 

 552.1 

 

 

 208.4 

 

 

 158.5 

 

 

 28.1 

 

Less:  Valuation Allowance

 

 4.0 

 

 

 -  

 

 

 -  

 

 

 -  

 

 

 23.1 

 

 

 -  

 

 

 -  

 

 

 -  

Net Deferred Tax Assets

$

 481.1 

 

$

 258.5 

 

$

 179.6 

 

$

 36.3 

 

$

 529.0 

 

$

 208.4 

 

$

 158.5 

 

$

 28.1 

Deferred Tax Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accelerated Depreciation and Other
  Plant-Related Differences

$

 1,378.6 

 

$

 1,296.9 

 

$

 596.6 

 

$

 385.8 

 

$

 1,238.1 

 

$

 1,179.4 

 

$

 526.6 

 

$

 361.1 

 

Property Tax Accruals

 

 58.1 

 

 

 25.0 

 

 

 7.4 

 

 

 12.8 

 

 

 49.3 

 

 

 25.3 

 

 

 7.1 

 

 

 5.9 

 

Regulatory Amounts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Regulatory Deferrals - Assets

 

 502.3 

 

 

 276.0 

 

 

 147.6 

 

 

 60.4 

 

 

 550.4 

 

 

 276.2 

 

 

 109.3 

 

 

 49.3 

 

 

Tax Effect - Tax Regulatory Assets

 

 166.9 

 

 

 35.5 

 

 

 15.9 

 

 

 9.3 

 

 

 160.1 

 

 

 36.0 

 

 

 16.3 

 

 

 18.2 

 

 

Goodwill Regulatory Asset - 1999 Merger

 -  

 

 

 174.4 

 

 

 -  

 

 

 -  

 

 

 -  

 

 

 181.6 

 

 

 -  

 

 

 -  

 

 

Derivative Assets

 

 32.6 

 

 

 -  

 

 

 -  

 

 

 -  

 

 

 29.0 

 

 

 0.5 

 

 

 -  

 

 

 -  

 

 

Other

 

 19.4 

 

 

 33.5 

 

 

 35.6 

 

 

 2.8 

 

 

 20.6 

 

 

 26.4 

 

 

 28.0 

 

 

 3.6 

Total Deferred Tax Liabilities

$

 2,157.9 

 

$

 1,841.3 

 

$

 803.1 

 

$

 471.1 

 

$

 2,047.5 

 

$

 1,725.4 

 

$

 687.3 

 

$

 438.1 


Carryforwards:  The following tables provide the amounts and expiration dates of state tax credit and loss carryforwards and federal tax credit and net operating loss carryforwards:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2014

 

 

 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

 

 

 

(Millions of Dollars)

NU

 

CL&P

 

Electric

 

PSNH

 

WMECO

 

Expiration Range

 

Federal Net Operating Loss

$

 168.8 

 

$

 -  

 

$

 -  

 

$

 91.8 

 

$

 12.7 

 

2031 - 2032

 

Federal Tax Credit

 

 16.3 

 

 

 0.1 

 

 

 0.2 

 

 

 11.1 

 

 

 -  

 

2031 - 2034

 

Federal Charitable Contribution

 

 19.4 

 

 

 -  

 

 

 -  

 

 

 -  

 

 

 -  

 

2016 - 2018

 

State Tax Credit

 

 99.7 

 

 

 71.0 

 

 

 -  

 

 

 -  

 

 

 -  

 

2014 - 2019

 

State Loss Carryforwards

 

 40.6 

 

 

 -  

 

 

 -  

 

 

 -  

 

 

 -  

 

2014 - 2034

 

State Charitable Contribution

 

 2.1 

 

 

 -  

 

 

 -  

 

 

 -  

 

 

 -  

 

2015 - 2018

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2013

 

 

 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

 

 

 

(Millions of Dollars)

NU

 

CL&P

 

Electric

 

PSNH

 

WMECO

 

Expiration Range

 

Federal Net Operating Loss

$

 451.3 

 

$

 145.8 

 

$

 -  

 

$

 161.8 

 

$

 53.3 

 

2031 - 2032

 

Federal Tax Credit

 

 8.0 

 

 

 -  

 

 

 -  

 

 

 7.6 

 

 

 -  

 

2031 - 2033

 

Federal Charitable Contribution

 

 33.7 

 

 

 -  

 

 

 -  

 

 

 -  

 

 

 -  

 

2015 - 2017

 

State Tax Credit

 

 104.7 

 

 

 86.8 

 

 

 -  

 

 

 -  

 

 

 -  

 

2013 - 2018

 

State Loss Carryforwards

 

 12.1 

 

 

 -  

 

 

 -  

 

 

 -  

 

 

 -  

 

2013 - 2015

 

State Charitable Contribution

 

 1.0 

 

 

 -  

 

 

 -  

 

 

 -  

 

 

 -  

 

2015 

 


In 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 $19.2 million at CL&P, net of tax, to reflect an update for expired state credits and latest estimate of usage.


For 2014, state credit and state loss carryforwards have been partially reserved by a valuation allowance of $4.4 million (net of federal income tax).  For 2013, state credit and state loss carryforwards have been partially reserved by a valuation allowance of $23.7 million (net of federal income tax).  


Unrecognized Tax Benefits:  A reconciliation of the activity in unrecognized tax benefits, all of which would impact the effective tax rate if recognized, is as follows:


(Millions of Dollars)

NU

 

CL&P

Balance as of January 1, 2012

$

 73.5 

 

$

 46.5 

 

Gross Increases - Current Year

 

10.3 

 

 

2.5 

 

Gross Increases - Prior Year

 

0.1 

 

 

 - 

 

Gross Decreases - Prior Year

 

(0.8)

 

 

 - 

Balance as of December 31, 2012

 

83.1 

 

 

49.0 

 

Gross Increases - Current Year

 

 8.2 

 

 

 2.1 

 

Gross Decreases - Prior Year

 

 (1.1)

 

 

 (0.3)

 

Settlements

 

 (49.8)

 

 

 (39.4)

 

Lapse of Statute of Limitations

 

 (2.2)

 

 

 -  

Balance as of December 31, 2013

 

38.2 

 

 

11.4 

 

Gross Increases - Current Year

 

 9.3 

 

 

 2.7 

 

Gross Increases - Prior Year

 

 0.3 

 

 

 0.2 

 

Lapse of Statute of Limitations

 

 (1.6)

 

 

 -  

Balance as of December 31, 2014

$

46.2 

 

$

14.3 




124


Interest and Penalties:  Interest on uncertain tax positions is recorded and generally classified as a component of Other Interest Expense on the statements of income.  However, when resolution of uncertainties results in the Company receiving interest income, any related interest benefit is recorded in Other Income, Net on the statements of income.  No penalties have been recorded.  The amount of interest expense/(income) on uncertain tax positions recognized and the related accrued interest payable/(receivable) are as follows:  


Other Interest

 

For the Years Ended December 31,

 

Accrued Interest

 

As of December 31,

Expense/(Income)

 

2014 

 

2013 

 

2012 

 

Expense

 

2014 

 

2013 

(Millions of Dollars)

 

 

 

 

 

 

 

 

 

 

(Millions of Dollars)

 

 

 

 

 

 

NU (1)

 

$

 0.4 

 

$

 (8.6)

 

$

 3.1 

 

NU

 

$

 1.9 

 

$

 1.5 

CL&P

 

 

 -  

 

 

 (4.0)

 

 

 1.3 

 

CL&P

 

 

 -  

 

 

 -  


(1)

NSTAR amounts were included in NU beginning April 10, 2012.  


Tax Positions:  During 2014, NU did not resolve any of its uncertain tax positions.


During 2013, NU received a Final Determination from the Connecticut Department of Revenue Services (DRS) that concluded its audit of NU's Connecticut income tax returns for the years 2005 through 2008.  The DRS Determination resulted in total NU and CL&P after-tax benefits of $13.6 million and $6.9 million, respectively, that included a reduction in NU and CL&P pre-tax interest expense of $8.7 million and $4 million, or $5.2 million and $2.4 million after-tax, respectively.  Further, the income tax expense impact resulted in a tax benefit to NU and CL&P of $8.4 million and $4.5 million after-tax, respectively.  


Open Tax Years:  The following table summarizes NU, CL&P, NSTAR Electric, PSNH and WMECO's tax years that remain subject to examination by major tax jurisdictions as of December 31, 2014:  


Description

 

Tax Years

Federal

 

2014 

Connecticut

 

2011 – 2014

Massachusetts

 

2011 – 2014

New Hampshire

 

2011 – 2014


NU estimates that during the next twelve months, differences of a non-timing nature could be resolved, resulting in a zero to $2 million decrease in unrecognized tax benefits by NU.  These estimated changes are not expected to have a material impact on the earnings of NU.  Other companies' impacts are not expected to be material.  


2014 Federal Legislation:  On December 19, 2014, the "Tax Increase Prevention Act of 2014" became law, which extended the accelerated deduction of depreciation to businesses through 2014.  This extended stimulus provides NU with cash flow benefits of approximately $200 million (approximately $70 million at CL&P, $50 million at NSTAR Electric, $35 million at PSNH, and $15 million at WMECO) in 2015.  


2013 Federal Legislation:  On January 2, 2013, the "American Taxpayer Relief Act of 2012" became law, which extended the accelerated deduction of depreciation to businesses through 2013.  This extended stimulus provided NU with cash flow benefits of approximately $300 million (approximately $95 million at CL&P, $85 million at NSTAR Electric, $35 million at PSNH, and $50 million at WMECO).  


On September 13, 2013, the Internal Revenue Service issued final Tangible Property regulations that are meant to simplify, clarify and make more administrable previously issued guidance.  NU is in compliance with the new regulations, but continues to evaluate several new potential elections.  


2013 Massachusetts:  On July 24, 2013, Massachusetts enacted a law that changed the income tax rate applicable to utility companies effective January 1, 2014, from 6.5 percent to 8 percent.  The tax law change required NU to remeasure its accumulated deferred income taxes and resulted in NU increasing its deferred tax liability with an offsetting regulatory asset of approximately $61 million at its utility companies ($46.3 million at NSTAR Electric and $9.8 million at WMECO).


11.

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.


Environmental reserves are accrued when assessments indicate it is probable that a liability has been incurred and an amount can be reasonably estimated.  The approach used estimates the liability based on the most likely action plan from a variety of available remediation options, including no action required or several different remedies ranging from establishing institutional controls to full site remediation and monitoring.


These estimates are subjective in nature as they take into consideration several different remediation options at each specific site.  The reliability and precision of these estimates can be affected by several factors, including new information concerning either the level of contamination at the site, the extent of NU, CL&P, NSTAR Electric, PSNH and WMECO's responsibility or the extent of remediation required, recently enacted laws and regulations or a change in cost estimates due to certain economic factors.




125


The amounts recorded as environmental liabilities included in Other Current Liabilities and Other Long-Term Liabilities on the balance sheets represent management's best estimate of the liability for environmental costs, and take into consideration site assessment, remediation and long-term monitoring costs.  The environmental liability also takes into account recurring costs of managing hazardous substances and pollutants, mandated expenditures to remediate previously contaminated sites and any other infrequent and non-recurring clean-up costs.  A reconciliation of the activity in the environmental reserves is as follows:


(Millions of Dollars)

NU

 

CL&P

 

NSTAR Electric

 

PSNH

 

WMECO

Balance as of January 1, 2013

$

 39.4 

 

$

 3.7 

 

$

 1.7 

 

$

 4.9 

 

$

 0.6 

Additions

 

 3.5 

 

 

 0.2 

 

 

 0.2 

 

 

 1.0 

 

 

 -  

Payments/Reductions

 

 (7.5)

 

 

 (0.5)

 

 

 (0.7)

 

 

 (0.5)

 

 

 (0.2)

Balance as of December 31, 2013

 

 35.4 

 

 

 3.4 

 

 

 1.2 

 

 

 5.4 

 

 

 0.4 

Additions

 

 12.7 

 

 

 1.0 

 

 

 -  

 

 

 0.1 

 

 

 0.2 

Payments/Reductions

 

 (4.8)

 

 

 (0.6)

 

 

 (0.1)

 

 

 (0.3)

 

 

 (0.1)

Balance as of December 31, 2014

$

 43.3 

 

$

 3.8 

 

$

 1.1 

 

$

 5.2 

 

$

 0.5 


These liabilities are estimated on an undiscounted basis and do not assume that any amounts are recoverable from insurance companies or other third parties.  The environmental reserves include sites at different stages of discovery and remediation and do not include any unasserted claims.


It is possible that new information or future developments could require a reassessment of the potential exposure to related environmental matters.  As this information becomes available, management will continue to assess the potential exposure and adjust the reserves accordingly.  


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 December 31, 2014

 

As of December 31, 2013

 

 

 

 

Reserve

 

 

 

 

Reserve

 

Number of Sites

 

(in millions)

 

Number of Sites

 

(in millions)

NU

 

 65 

 

$

 43.3 

 

 

 68 

 

$

 35.4 

CL&P

 

 16 

 

 

 3.8 

 

 

 18 

 

 

 3.4 

NSTAR Electric

 

 13 

 

 

 1.1 

 

 

 12 

 

 

 1.2 

PSNH

 

 13 

 

 

 5.2 

 

 

 15 

 

 

 5.4 

WMECO

 

 4 

 

 

 0.5 

 

 

 5 

 

 

 0.4 


Included in the NU number of sites and reserve amounts above are former MGP sites that were operated several decades ago and manufactured gas from coal and other processes, which resulted in certain by-products remaining in the environment that may pose a potential risk to human health and the environment. The reserve balance related to these former MGP sites was $38.8 million and $31.4 million as of December 31, 2014 and 2013, respectively, and relates primarily to the natural gas business segment. The increase in the reserve balance for the MGP sites was due to the completion of the site assessment at three sites.  The assessments provided new information related to the extent and nature of the contamination and the costs of required remediation.  


As of December 31, 2014, for 5 environmental sites (1 for CL&P, and 1 for WMECO) that are included in the Company's reserve for environmental costs, the information known and nature of the remediation options at those sites allow for the Company to estimate the range of losses for environmental costs.  As of December 31, 2014, $17.7 million ($1 million for CL&P and $0.3 million for WMECO) had been accrued as a liability for these sites, which represent management's best estimates of the liabilities for environmental costs.  These amounts are the best estimates with estimated ranges of additional losses from zero to $24 million.  


As of December 31, 2014, for 15 environmental sites (3 for CL&P, 3 for NSTAR Electric and 2 for PSNH) that are included in the Company's reserve for environmental costs, management cannot reasonably estimate the exposure to loss in excess of the reserve, or range of loss, as these sites are under investigation and/or there is significant uncertainty as to what remedial actions, if any, the Company may be required to undertake.  As of December 31, 2014, $13.4 million ($1.4 million for CL&P, $0.2 million for PSNH) had been accrued as a liability for these sites.  As of December 31, 2014, for the remaining 45 environmental sites (12 for CL&P, 10 for NSTAR Electric, 11 for PSNH, and 3 for WMECO) that are included in the Company's reserve for environmental costs, the $12.2 million accrual ($1.4 million for CL&P, $1.1 million for NSTAR Electric, $5 million for PSNH, and $0.2 million for WMECO) represents management's best estimate of the liability and no additional loss is anticipated.


CERCLA:  Of the total environmental sites, 9 sites (1 for CL&P, 3 for NSTAR Electric and 3 for PSNH) are superfund sites under the federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and its amendments or state equivalents for which the Company has been notified that it is a potentially responsible party but for which the site assessment and remediation are not being managed by the Company.  As of December 31, 2014, a liability of $0.7 million accrued on these sites represents management's best estimate of its potential remediation costs with respect to these superfund sites.


Environmental Rate Recovery:  PSNH, NSTAR Gas and Yankee Gas have rate recovery mechanisms for MGP related environmental costs.  CL&P recovers a certain level of environmental costs currently in rates but does not have an environmental cost recovery tracking mechanism.  Accordingly, changes in CL&P's environmental reserves impact CL&P's Net Income.  NSTAR Electric and WMECO do not have a separate regulatory mechanism to recover environmental costs from its customers, and changes in NSTAR Electric's and WMECO's environmental reserves impact Net Income.  




126





B.

Long-Term Contractual Arrangements

 

Estimated Future Annual Costs:  The estimated future annual costs of significant long-term contractual arrangements as of December 31, 2014 are as follows:

 

 

NU

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Millions of Dollars)

2015 

 

2016 

 

2017 

 

2018 

 

2019 

 

Thereafter

 

Total

 

Supply and Stranded Cost

$

196.6 

 

$

169.2 

 

$

101.9 

 

$

65.3 

 

$

38.1 

 

$

82.4 

 

$

653.5 

 

Renewable Energy

 

204.3 

 

 

240.5 

 

 

239.6 

 

 

204.2 

 

 

202.9 

 

 

1,994.6 

 

 

3,086.1 

 

Peaker CfDs

 

26.3 

 

 

25.4 

 

 

10.5 

 

 

 -   

 

 

 -   

 

 

 -   

 

 

62.2 

 

Natural Gas Procurement

 

133.7 

 

 

116.3 

 

 

45.6 

 

 

31.9 

 

 

25.8 

 

 

85.1 

 

 

438.4 

 

Coal, Wood and Other

 

99.0 

 

 

25.2 

 

 

5.0 

 

 

5.0 

 

 

1.9 

 

 

15.0 

 

 

151.1 

 

Transmission Support Commitments

 

25.9 

 

 

21.6 

 

 

19.0 

 

 

21.2 

 

 

21.3 

 

 

21.3 

 

 

130.3 

 

Total

$

685.8 

 

$

598.2 

 

$

421.6 

 

$

327.6 

 

$

290.0 

 

$

2,198.4 

 

$

4,521.6 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CL&P

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Millions of Dollars)

2015 

 

2016 

 

2017 

 

2018 

 

2019 

 

Thereafter

 

Total

 

Supply and Stranded Cost

$

134.3 

 

$

136.8 

 

$

79.0 

 

$

42.0 

 

$

25.0 

 

$

43.6 

 

$

460.7 

 

Renewable Energy

 

61.2 

 

 

70.3 

 

 

71.3 

 

 

72.1 

 

 

72.1 

 

 

715.9 

 

 

1,062.9 

 

Peaker CfDs

 

26.3 

 

 

25.4 

 

 

10.5 

 

 

 -   

 

 

 -   

 

 

 -   

 

 

62.2 

 

Transmission Support Commitments

 

10.2 

 

 

8.5 

 

 

7.5 

 

 

8.4 

 

 

8.4 

 

 

8.4 

 

 

51.4 

 

Yankee Billings

 

1.4 

 

 

0.8 

 

 

0.8 

 

 

0.9 

 

 

0.9 

 

 

11.8 

 

 

16.6 

 

Total

$

233.4 

 

$

241.8 

 

$

169.1 

 

$

123.4 

 

$

106.4 

 

$

779.7 

 

$

1,653.8 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NSTAR Electric

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Millions of Dollars)

2015 

 

2016 

 

2017 

 

2018 

 

2019 

 

Thereafter

 

Total

 

Supply and Stranded Cost

$

34.3 

 

$

14.1 

 

$

4.8 

 

$

5.5 

 

$

5.5 

 

$

31.4 

 

$

95.6 

 

Renewable Energy

 

85.4 

 

 

99.9 

 

 

96.9 

 

 

59.6 

 

 

57.7 

 

 

319.8 

 

 

719.3 

 

Transmission Support Commitments

 

8.1 

 

 

6.7 

 

 

5.9 

 

 

6.6 

 

 

6.6 

 

 

6.6 

 

 

40.5 

 

Yankee Billings

 

0.5 

 

 

0.3 

 

 

0.3 

 

 

0.3 

 

 

0.3 

 

 

4.0 

 

 

5.7 

 

Total

$

128.3 

 

$

121.0 

 

$

107.9 

 

$

72.0 

 

$

70.1 

 

$

361.8 

 

$

861.1 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

PSNH

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Millions of Dollars)

2015 

 

2016 

 

2017 

 

2018 

 

2019 

 

Thereafter

 

Total

 

Supply and Stranded Cost

$

28.0 

 

$

18.3 

 

$

18.1 

 

$

17.8 

 

$

7.6 

 

$

7.4 

 

$

97.2 

 

Renewable Energy

 

57.7 

 

 

67.9 

 

 

69.0 

 

 

70.1 

 

 

70.7 

 

 

932.4 

 

 

1,267.8 

 

Coal, Wood and Other

 

99.0 

 

 

25.2 

 

 

5.0 

 

 

5.0 

 

 

1.9 

 

 

15.0 

 

 

151.1 

 

Transmission Support Commitments

 

5.5 

 

 

4.6 

 

 

4.0 

 

 

4.5 

 

 

4.5 

 

 

4.5 

 

 

27.6 

 

Yankee Billings

 

0.4 

 

 

0.3 

 

 

0.3 

 

 

0.3 

 

 

0.3 

 

 

4.7 

 

 

6.3 

 

Total

$

190.6 

 

$

116.3 

 

$

96.4 

 

$

97.7 

 

$

85.0 

 

$

964.0 

 

$

1,550.0 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

WMECO

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Millions of Dollars)

2015 

 

2016 

 

2017 

 

2018 

 

2019 

 

Thereafter

 

Total

 

Renewable Energy

$

 -   

 

$

2.4 

 

$

2.4 

 

$

2.4 

 

$

2.4 

 

$

26.5 

 

$

36.1 

 

Transmission Support Commitments

 

2.1 

 

 

1.8 

 

 

1.6 

 

 

1.7 

 

 

1.8 

 

 

1.8 

 

 

10.8 

 

Yankee Billings

 

0.3 

 

 

0.2 

 

 

0.2 

 

 

0.2 

 

 

0.2 

 

 

3.0 

 

 

4.1 

 

Total

$

2.4 

 

$

4.4 

 

$

4.2 

 

$

4.3 

 

$

4.4 

 

$

31.3 

 

$

51.0 

 


Supply and Stranded Cost:  CL&P, NSTAR Electric and PSNH have various IPP contracts or purchase obligations for electricity, including payment obligations resulting from the buydown of electricity purchase contracts.  Such contracts extend through 2024 for CL&P, 2030 for NSTAR Electric and 2023 for PSNH.


In addition, CL&P, along with UI, has four capacity CfDs for a total of approximately 787 MW of capacity consisting of three generation projects and one demand response project.  The capacity CfDs 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 capacity market prices received by the generation facilities in the ISO-NE capacity markets.  CL&P has a sharing agreement with UI, whereby UI will share 20 percent of the costs and benefits of these contracts.  CL&P's portion of the costs and benefits of these contracts will be paid by or refunded to CL&P's customers.  


The contractual obligations table does not include CL&P's SS or LRS, or NSTAR Electric's or WMECO's default service contracts, the amounts of which vary with customers' energy needs.  The contractual obligations table also does not include PSNH's short-term power supply management.  


Renewable Energy:  Renewable energy contracts include non-cancellable commitments under contracts of CL&P, NSTAR Electric, PSNH, and WMECO for the purchase of energy and capacity from renewable energy facilities.  Such contracts extend through 2035 for CL&P, 2030 for NSTAR Electric, 2033 for PSNH and 2030 for WMECO.  


The contractual obligations table does not include long-term commitments signed by CL&P, NSTAR Electric and WMECO, as required by the PURA and DPU, for the purchase of renewable energy and related products that are contingent on the future construction of energy facilities.


Peaker CfDs:  In 2008, CL&P entered into three CfDs with developers of peaking generation units approved by the PURA (Peaker CfDs).  These units have a total of approximately 500 MW of peaking capacity.  As directed by the PURA, CL&P and UI have entered into a sharing agreement, whereby CL&P is responsible for 80 percent and UI for 20 percent of the net costs or benefits of these CfDs.  The Peaker CfDs pay the generation facility owner the difference between capacity, forward reserve and energy market revenues and a cost-of-service payment stream for 30 years.  The ultimate cost or benefit to CL&P under these contracts will depend on the costs of plant operation and the prices that the projects receive for capacity



127


and other products in the ISO-NE markets.  CL&P's portion of the amounts paid or received under the Peaker CfDs will be recoverable from or refunded to CL&P's customers.  


Natural Gas Procurement:  NU's natural gas distribution businesses have long-term contracts for the purchase, transportation and storage of natural gas in the normal course of business as part of its portfolio of supplies.  These contracts extend through 2029.  


Coal, Wood and Other:  PSNH has entered into various arrangements for the purchase of coal, wood and the transportation services for fuel supply for its electric generating assets.  Also included in the table above is a contract for capacity on the Portland Natural Gas Transmission System (PNGTS) pipeline that extends through 2018.  The costs on this contract of $11.4 million are not recoverable from customers.


Transmission Support Commitments:  Along with other New England utilities, CL&P, NSTAR Electric, PSNH and WMECO entered into agreements in 1985 to support transmission and terminal facilities that were built to import electricity from the Hydro-Québec system in Canada.  CL&P, NSTAR Electric, PSNH and WMECO are obligated to pay, over a 30-year period ending in 2020, their proportionate shares of the annual operation and maintenance expenses and capital costs of those facilities.  


The total costs incurred under these agreements were as follows:


NU

For the Years Ended December 31,

(Millions of Dollars)

2014

 

2013 

 

2012 (1)

Supply and Stranded Cost

$

99.2 

 

$

141.0 

 

$

216.8 

Renewable Energy

 

114.4 

 

 

91.3 

 

 

48.7 

Peaker CfDs

 

18.1 

 

 

51.9 

 

 

59.3 

Natural Gas Procurement

 

482.5 

 

 

349.8 

 

 

243.1 

Coal, Wood and Other

 

120.5 

 

 

112.6 

 

 

105.2 

Transmission Support Commitments

 

25.0 

 

 

24.9 

 

 

24.8 


 

 

For the Years Ended December 31,

 

 

2014 

 

2013 

 

2012 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

(Millions of Dollars)

CL&P

 

Electric

 

PSNH

 

WMECO

 

CL&P

 

Electric

 

PSNH

 

WMECO

 

CL&P

 

Electric

 

PSNH

 

WMECO

Supply and Stranded Cost

$

 63.0 

 

$

 7.0 

 

$

 26.0 

 

$

 3.2 

 

$

 77.6 

 

$

 32.4 

 

$

 29.0 

 

$

 2.0 

 

$

 158.2 

 

$

 36.3 

 

$

 30.5 

 

$

 0.9 

Renewable Energy

 

 0.7 

 

 

 87.4 

 

 

 26.3 

 

 

 -  

 

 

 -  

 

 

 84.9 

 

 

 6.4 

 

 

 -  

 

 

 -  

 

 

 60.2 

 

 

 4.1 

 

 

 -  

Peaker CfDs

 

 18.1 

 

 

 -  

 

 

 -  

 

 

 -  

 

 

 51.9 

 

 

 -  

 

 

 -  

 

 

 -  

 

 

 59.3 

 

 

 -  

 

 

 -  

 

 

 -  

Coal, Wood and Other

 

 -  

 

 

 -  

 

 

 120.5 

 

 

 -  

 

 

 -  

 

 

 -  

 

 

 112.6 

 

 

 -  

 

 

 -  

 

 

 -  

 

 

 105.2 

 

 

 -  

Transmission Support

  Commitments

 

 9.9 

 

 

 7.7 

 

 

 5.3 

 

 

 2.1 

 

 

 9.8 

 

 

 7.7 

 

 

 5.3 

 

 

 2.1 

 

 

 9.6 

 

 

 7.6 

 

 

 5.2 

 

 

 2.0 


(1)

NSTAR amounts were included in NU beginning April 10, 2012.


C.

Contractual Obligations - Yankee Companies

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


CL&P, NSTAR Electric, PSNH and WMECO's percentage share of the obligations to support the Yankee Companies under FERC-approved rate tariffs is the same as their respective ownership percentages in the Yankee Companies.  For further information on the ownership percentages, see Note 1J, "Summary of Significant Accounting Policies - Equity Method Investments," to the financial statements.  


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


Spent Nuclear Fuel Litigation:  

DOE Phase I Damages – In 1998, the Yankee Companies filed separate complaints against the DOE in the Court of Federal Claims seeking monetary damages resulting from the DOE's failure to begin accepting spent nuclear fuel for disposal by January 31, 1998 pursuant to the terms of the 1983 spent fuel and high level waste disposal contracts between the Yankee Companies and the DOE (DOE Phase I Damages).  Phase I covered damages for the period 1998 through 2002.  Following multiple appeals and cross-appeals, in December 2012, the judgment awarding CYAPC $39.6 million, YAEC $38.3 million and MYAPC $81.7 million became final.


In January 2013, the proceeds from the DOE Phase I Damages Claim were received by the Yankee Companies and transferred to each Yankee Company's respective decommissioning trust.  As a result of NU's consolidation of CYAPC and YAEC, the financial statements reflected an increase of $77.9 million in marketable securities for CYAPC and YAEC's Phase I Damage awards that were invested in the nuclear decommissioning trusts in 2013.


In June 2013, FERC approved CYAPC, YAEC and MYAPC to reduce rates in their wholesale power contracts through the application of the DOE proceeds for the benefit of customers.  Changes to the terms of the wholesale power contracts became effective on July 1, 2013.  In accordance with the FERC order, CL&P, NSTAR Electric, PSNH and WMECO began receiving the benefit of the DOE proceeds, and the benefits have been passed on to customers.



128



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.


DOE Phase II Damages - In December 2007, the Yankee Companies each filed subsequent lawsuits against the DOE seeking recovery of actual damages incurred related to the alleged failure of the DOE to provide for a permanent facility to store spent nuclear fuel generated in years 2001 through 2008 for CYAPC and YAEC and from 2002 through 2008 for MYAPC (DOE Phase II Damages).  In November 2013, the court issued a final judgment awarding CYAPC $126.3 million, YAEC $73.3 million, and MYAPC $35.8 million.  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.


In March and April 2014, CYAPC, YAEC and MYAPC received payment of $126.3 million, $73.3 million and $35.8 million, respectively, of the DOE Phase II Damages proceeds and 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 December 31, 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 – In August 2013, the Yankee Companies each filed subsequent lawsuits against the DOE seeking recovery of actual damages incurred in the years 2009 through 2012.  The presiding judge issued a Pre-Trial Scheduling Order on September 3, 2014 that set the case for trial from June 30 to July 2, 2015.  


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 December 31, 2014:  


 

 

 

 

Maximum Exposure

 

 

 

 

Subsidiary

 

Description

 

(in millions)

 

 

Expiration Dates

 

 

 

 

 

 

 

 

 

 

Various

 

Surety Bonds  (1)

 

$

60.0 

 

 

2015 - 2016

 

 

 

 

 

 

 

 

 

NUSCO and Rocky River Realty Company

 

Lease Payments for Vehicles and Real Estate

 

$

14.4 

 

 

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.  


E.

FERC Base ROE Complaints

Beginning in 2011, several New England state attorneys general, state regulatory commissions, consumer advocates, consumer groups, municipal parties and other parties (the "Complainants") jointly filed three separate complaints at FERC.  In the first complaint, filed in 2011, the Complainants alleged that the NETOs' base ROE of 11.14 percent that was utilized since 2006 was unjust and unreasonable, asserted that the rate was excessive due to changes in the capital markets, and sought an order to reduce it prospectively from the date of the final FERC order and for the 15-month period beginning October 1, 2011 to December 31, 2012 (the "first complaint refund period").  In the pursuant second and third complaints, filed in 2012 and 2014, respectively, the Complainants challenged the NETOs' base ROE and sought refunds for the 15-month periods beginning December 27, 2012 and July 31, 2014, respectively.    


In 2014, the FERC determined that the base ROE should be set at 10.57 percent for the first complaint refund period and that a utility's total or maximum ROE should not exceed the top of the new zone of reasonableness (7.03 percent to 11.74 percent).   The FERC ordered the NETOs to provide refunds to customers for the first complaint refund period and set the new base ROE of 10.57 percent prospectively from October 16, 2014.  In late 2014, the NETOs made a compliance filing, and began refunding amounts from the first complaint period, inclusive of incentive ROE adders that exceeded the 11.74 percent as compared to the total company transmission ROE.  Complainants have challenged the compliance filing.




129


As a result of the actions taken by the FERC and other developments in this matter, NU recorded reserves in 2013 and 2014 to recognize the potential financial impacts of the first and second complaints.  The Company is unable to determine any amount related to the third complaint.  The following is a summary of the cumulative pre-tax reserves (excluding interest) established by the Company in 2013 and 2014:  


 

 

NU

 

 

 

 

 

 

 

 

 

 

 

For the Years Ended December 31,

 

 

 

 

 

 

 

 

 

(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)

 

 - 

 

 

 8.4 

 

 

 8.4 

 

 

 

 

 

 

 

 

 

Cumulative Reserve

$

 23.7 

 

$

 37.0 

 

$

 60.7 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CL&P

 

NSTAR Electric

 

 

For the Years Ended December 31,

 

For the Years Ended December 31,

(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)

 

 - 

 

 

 6.7 

 

 

 6.7 

 

 

 - 

 

 

 - 

 

 

 - 

Cumulative Reserve

$

 12.8 

 

$

 20.7 

 

$

 33.5 

 

$

 5.7 

 

$

 7.9 

 

$

 13.6 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

PSNH

 

WMECO

 

 

For the Years Ended December 31,

 

For the Years Ended December 31,

(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)

 

 - 

 

 

 - 

 

 

 - 

 

 

 - 

 

 

 1.7 

 

 

 1.7 

Cumulative Reserve

$

 2.3 

 

$

 2.8 

 

$

 5.1 

 

$

 2.9 

 

$

 5.6 

 

$

 8.5 


As of December 31, 2014, the cumulative reserves above do not reflect refunds totaling $4.8 million at NU, $2.7 million at CL&P, $1 million at NSTAR Electric, $0.5 million at PSNH and $0.6 million at WMECO for the first complaint refund period.  


The aggregate after-tax net charge to 2014 earnings resulting from the 2014 FERC orders totaled $22.4 million at NU, $12.4 million at CL&P, $4.9 million at NSTAR Electric, $1.7 million at PSNH and $3.4 million at WMECO.  In 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.


Although management is uncertain on the final outcome on the second and third complaints regarding the base ROE and the incentive ROE adder, management believes the current reserves established are appropriate to reflect probable and reasonably estimable refunds.


F.

2014 Comprehensive Settlement Agreement

On December 31, 2014, NSTAR Electric, NSTAR Gas and the Massachusetts Attorney General filed a comprehensive settlement agreement with the DPU.  The comprehensive settlement agreement included resolution of the outstanding NSTAR Electric CPSL program filings for the periods 2006 through 2011, the NSTAR Electric and NSTAR Gas PAM and energy efficiency-related customer billing adjustments reported in 2012, and the NSTAR Electric energy efficiency program filings regarding LBR for the periods 2008 through 2011.  If approved by the DPU, NSTAR Electric and NSTAR Gas will be required to refund a total of $44.7 million to their respective customers, which was included in regulatory liabilities as of December 31, 2014.  Upon the DPU's approval, NSTAR Electric will adjust its regulatory liabilities, which it expects will result in a benefit of $23 million in the first quarter of 2015.  Management expects a response from the DPU in the first quarter of 2015.   


G.

Basic Service Bad Debt Adder

In accordance with a generic 2005 DPU order, electric utilities in Massachusetts recover the energy-related portion of bad debt costs in their Basic Service rates.  In 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.  NSTAR Electric's position was that it had fully removed the collection of energy-related bad debt costs from its distribution rates effective January 1, 2006.  Therefore, no further adjustment to distribution rates was warranted.  In 2012, the SJC vacated the DPU order and remanded the matter to the DPU for further review.  


As of December 31, 2014, NSTAR Electric has a total deferred regulatory asset of approximately $33 million of costs associated with energy-related bad debt.

On January 7, 2015, the DPU issued an order on remand stating that NSTAR Electric had, in fact, removed energy-related bad debt costs from distribution rates effective January 1, 2006.  The DPU order approved NSTAR Electric's 2005 and 2006 reconciliation filings and ordered NSTAR Electric and the Massachusetts Attorney General to collaborate on the submission of a proposal for the reconciliation of energy-related bad debt costs for the open years of 2007 through 2014 by April 7, 2015.  Management expects to present a proposal to the Attorney General in the first quarter of 2015 with a decision from the DPU later in 2015.  




130


H.

Litigation and Legal Proceedings

NU, including CL&P, NSTAR Electric, PSNH and WMECO, are involved in legal, tax and regulatory proceedings regarding matters arising in the ordinary course of business, which involve management's assessment to determine the probability of whether a loss will occur and, if probable, its best estimate of probable loss.  The Company records and discloses losses when these losses are probable and reasonably estimable, and discloses matters when losses are probable but not estimable or when losses are reasonably possible.  Legal costs related to the defense of loss contingencies are expensed as incurred.


12.

LEASES


NU, including CL&P, NSTAR Electric, PSNH and WMECO, has entered into lease agreements, some of which are capital leases, for the use of data processing and office equipment, vehicles, service centers, and office space.  In addition, CL&P, NSTAR Electric, PSNH and WMECO incur costs associated with leases entered into by NUSCO and Rocky River Realty Company, which are included below in their respective operating lease rental expenses and future minimum rental payments.  These intercompany lease amounts are eliminated on an NU consolidated basis.  The provisions of the NU, CL&P, NSTAR Electric, PSNH, and WMECO lease agreements generally contain renewal options.  Certain lease agreements contain payments impacted by the commercial paper rate plus a credit spread or the consumer price index.


Operating lease rental payments charged to expense are as follows:


 

 

 

 

 

 

 

 

NSTAR

 

 

 

 

 

(Millions of Dollars)

NU (1)

 

CL&P

 

Electric

 

PSNH

 

WMECO

2014 

$

14.3 

 

$

 6.0 

 

$

7.8 

 

$

1.5 

 

$

1.2 

2013 

 

 16.3 

 

 

 8.1 

 

 

 6.7 

 

 

 1.7 

 

 

 2.9 

2012 

 

 14.8 

 

 

 8.2 

 

 

 6.2 

 

 

2.5 

 

 

3.0 


(1)

NSTAR amounts were included in NU beginning April 10, 2012.  


Future minimum rental payments, excluding executory costs, such as property taxes, state use taxes, insurance, and maintenance, under long-term noncancelable leases, as of December 31, 2014 are as follows:


Operating Leases

 

 

 

 

 

 

NSTAR

 

 

 

 

 

 

(Millions of Dollars)

NU

 

CL&P

 

Electric

 

PSNH

 

WMECO

2015 

$

20.1 

 

$

4.3 

 

$

10.0 

 

$

1.1 

 

$

1.2 

2016 

 

17.6 

 

 

3.8 

 

 

8.8 

 

 

1.0 

 

 

1.0 

2017 

 

14.6 

 

 

2.6 

 

 

7.7 

 

 

0.8 

 

 

0.8 

2018 

 

10.5 

 

 

1.5 

 

 

5.8 

 

 

0.6 

 

 

0.6 

2019 

 

8.6 

 

 

1.1 

 

 

4.7 

 

 

0.5 

 

 

0.6 

Thereafter

 

22.5 

 

 

4.0 

 

 

10.4 

 

 

1.5 

 

 

2.5 

Future minimum lease payments

$

93.9 

 

$

17.3 

 

$

47.4 

 

$

5.5 

 

$

6.7 


Capital Leases

 

 

 

 

 

 

 

 

(Millions of Dollars)

NU

 

CL&P

 

PSNH

2015 

$

2.4 

 

$

2.0 

 

$

0.4 

2016 

 

2.2 

 

 

1.9 

 

 

0.3 

2017 

 

2.1 

 

 

2.0 

 

 

0.1 

2018 

 

2.1 

 

 

2.0 

 

 

0.1 

2019 

 

2.0 

 

 

2.0 

 

 

Thereafter

 

3.5 

 

 

3.5 

 

 

Future minimum lease payments

 

14.3 

 

 

13.4 

 

 

0.9 

Less amount representing interest

 

4.9 

 

 

5.0 

 

 

Present value of future minimum lease payments

$

9.4 

 

$

8.4 

 

$

0.9 


CL&P entered into certain contracts for the purchase of energy that qualify as leases.  These contracts do not have minimum lease payments and therefore are not included in the tables above.  However, such contracts have been included in the contractual obligations table in Note 11B, "Commitments and Contingencies - Long-Term Contractual Arrangements," to the financial statements.  


13.

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 December 31,

 

 

2014 

 

2013 

NU

Carrying

 

Fair

 

Carrying

 

Fair

(Millions of Dollars)

Amount

 

Value

 

Amount

 

Value

Preferred Stock Not Subject
  to Mandatory Redemption

$

 155.6 

 

$

 153.6 

 

$

 155.6 

 

$

 152.7 

Long-Term Debt

 

 8,851.6 

 

 

 9,451.2 

 

 

 8,310.2 

 

 

 8,443.1 




131






 

 

As of December 31, 2014

 

 

CL&P

 

NSTAR Electric

 

PSNH

 

WMECO

 

 

Carrying

 

Fair

 

Carrying

 

Fair

 

Carrying

 

Fair

 

Carrying

 

Fair

(Millions of Dollars)

Amount

 

Value

 

Amount

 

Value

 

Amount

 

Value

 

Amount

 

Value

Preferred Stock Not Subject
  to Mandatory Redemption

$

 116.2 

 

$

 112.0 

 

$

 43.0 

 

$

 41.6 

 

$

 - 

 

$

 - 

 

$

 - 

 

$

 - 

Long-Term Debt

 

 2,842.0 

 

 

 3,214.5 

 

 

 1,797.4 

 

 

 1,993.5 

 

 

 1,076.3 

 

 

 1,137.9 

 

 

 628.5 

 

 

 689.4 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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


14.

ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)


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


 

 

For the Year Ended December 31, 2014

 

For the Year Ended December 31, 2013

 

Qualified

 

Unrealized

 

 

 

 

 

Qualified

 

Unrealized

 

 

 

 

 

Cash Flow

 

Gains/(Losses)

 

Defined

 

 

 

Cash Flow

 

Gains/(Losses)

 

Defined

 

 

 

Hedging

 

on Marketable

 

Benefit

 

 

 

Hedging

 

on Marketable

 

Benefit

 

 

(Millions of Dollars)

Instruments

 

 Securities

 

Plans

 

Total

 

Instruments

 

 Securities

 

Plans

 

Total

AOCI as of January 1st

 (14.4)

 

 0.4 

 

 (32.0)

 

 (46.0)

 

 (16.4)

 

 1.3 

 

 (57.8)

 

 (72.9)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

OCI Before Reclassifications

 

 -  

 

 

 0.3 

 

 

 (34.2)

 

 

 (33.9)

 

 

 -   

 

 

 (0.9)

 

 

 19.4 

 

 

 18.5 

Amounts Reclassified from AOCI

 

 2.0 

 

 

 -  

 

 

 3.9 

 

 

 5.9 

 

 

2.0 

 

 

 -  

 

 

6.4 

 

 

8.4 

Net OCI

 

2.0 

 

 

0.3 

 

 

(30.3)

 

 

(28.0)

 

 

2.0 

 

 

(0.9)

 

 

25.8 

 

 

26.9 

AOCI as of December 31st

$

(12.4)

 

$

0.7 

 

$

(62.3)

 

$

(74.0)

 

$

(14.4)

 

$

0.4 

 

$

(32.0)

 

$

(46.0)


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 tax effects of Defined Benefit Plan OCI amounts before reclassifications, which relate to actuarial gains and losses that arose during 2014, 2013 and 2012 were recognized in AOCI as net deferred tax assets of $22.3 million and $6.2 million in 2014 and 2012, respectively, and net deferred tax liabilities of $11.4 million in 2013.


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


 

For the Years Ended December 31,

 

 

 

2014

 

2013

 

2012

 

 

 

Amounts Reclassified

 

Amounts Reclassified

 

Amounts Reclassified

 

Statements of Income

(Millions of Dollars)

from AOCI

 

from AOCI

 

from AOCI

 

Line Item Impacted

Qualified Cash Flow Hedging Instruments

$

(3.4)

 

$

(3.4)

 

$

(3.3)

 

Interest Expense

Tax Effect

 

1.4 

 

 

1.4 

 

 

1.3 

 

Income Tax Expense

Qualified Cash Flow Hedging Instruments, Net of Tax

$

(2.0)

 

$

(2.0)

 

$

(2.0)

 

 

 

 

 

 

 

 

 

 

 

 

 

Defined Benefit Plan Costs:

 

 

 

 

 

 

 

 

 

 

  Amortization of Actuarial Losses

$

(6.2)

 

$

(10.5)

 

$

(8.9)

 

Operations and Maintenance (1)

  Amortization of Prior Service Cost

 

(0.2)

 

 

(0.2)

 

 

(0.2)

 

Operations and Maintenance (1)

  Amortization of Transition Obligation

 

 

 

 

 

(0.2)

 

Operations and Maintenance  (1)

Total Defined Benefit Plan Costs

 

(6.4)

 

 

(10.7)

 

 

(9.3)

 

 

Tax Effect

 

2.5 

 

 

4.3 

 

 

3.5 

 

Income Tax Expense

Defined Benefit Plan Costs, Net of Tax

$

(3.9)

 

$

(6.4)

 

$

(5.8)

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Amounts Reclassified from AOCI, Net of Tax

$

(5.9)

 

$

(8.4)

 

$

(7.8)

 

 




132


(1)

These amounts are included in the computation of net periodic Pension, SERP and PBOP costs.  See Note 9A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pensions," for further information.


As of December 31, 2014, it is estimated that a pre-tax amount of $3.5 million ($0.7 million for CL&P, $2 million for PSNH and $0.6 million for WMECO) will be reclassified from AOCI as a decrease to Net Income over the next 12 months as a result of the amortization of the interest rate swap agreements, which have been settled.  In addition, it is estimated that a pre-tax amount of $6.9 million will be reclassified from AOCI as a decrease to Net Income over the next 12 months as a result of the amortization of Pension, SERP and PBOP costs.


15.

DIVIDEND RESTRICTIONS


NU parent's ability to pay dividends may be affected by certain state statutes, the ability of its subsidiaries to pay common dividends and the leverage restriction tied to its consolidated total debt to total capitalization ratio requirement in its revolving credit agreement.  


CL&P, NSTAR Electric, PSNH and WMECO are subject to Section 305 of the Federal Power Act that makes it unlawful for a public utility to make or pay a dividend from any funds "properly included in its capital account."  Management believes that this Federal Power Act restriction, as applied to CL&P, NSTAR Electric, PSNH and WMECO, would not be construed or applied by the FERC to prohibit the payment of dividends for lawful and legitimate business purposes from retained earnings.  In addition, certain state statutes may impose additional limitations on such companies and on Yankee Gas and NSTAR Gas.  Such state law restrictions do not restrict payment of dividends from retained earnings or net income.  Pursuant to the joint revolving credit agreement of NU, CL&P, PSNH, WMECO, Yankee Gas and NSTAR Gas, and the NSTAR Electric revolving credit agreement, each company is required to maintain consolidated total debt to total capitalization ratio of no greater than 65 percent at all times.  As of December 31, 2014, all companies were in compliance with such covenant.  The Retained Earnings balances subject to these restrictions were $2.4 billion for NU, $1.1 billion for CL&P, $1.5 billion for NSTAR Electric, $486.5 million for PSNH and $178.8 million for WMECO as of December 31, 2014.  As of December 31, 2014, NU, CL&P, NSTAR Electric, PSNH, WMECO, Yankee Gas and NSTAR Gas were in compliance with all such provisions of the revolving credit agreements that may restrict the payment of dividends.  PSNH is further required to reserve an additional amount under its FERC hydroelectric license conditions.  As of December 31, 2014, $13 million of PSNH's Retained Earnings was subject to restriction under its FERC hydroelectric license conditions and PSNH was in compliance with this provision.  


16.

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

 

Issued

 

Per Share

 

as of December 31,

 

as of December 31,

 

Par Value

 

2014 and 2013

 

2014 

 

2013 

NU

$

 

380,000,000 

 

 

 333,359,172 

 

 

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 December 31, 2014 and 2013, there were 16,375,835 and 17,796,672 NU common shares held as treasury shares, respectively.  As of December 31, 2014 and 2013, NU common shares outstanding were 316,983,337 and 315,273,559, respectively.  


17.

PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION


The CL&P and NSTAR Electric preferred stock is not subject to mandatory redemption and is presented as a noncontrolling interest of a subsidiary in NU's financial statements.


CL&P Preferred Stock:  CL&P's charter authorizes it to issue up to 9 million shares of preferred stock ($50 par value per share).  The issuance of additional preferred shares would be subject to PURA approval.  Preferred stockholders have liquidation rights equal to the par value of the preferred stock, which they would receive in preference to any distributions to any junior stock.  Were there to be a shortfall, all preferred stockholders would share ratably in available liquidation assets.  


NSTAR Electric Preferred Stock:  NSTAR Electric is authorized to issue 2,890,000 shares ($100 par value per share).  NSTAR Electric has two outstanding series of cumulative preferred stock.  Upon liquidation, holders of cumulative preferred stock are entitled to receive a liquidation preference before any distribution to holders of common stock.  The liquidation preference for each outstanding series of cumulative preferred stock is equal to the par value, plus accrued and unpaid dividends.  Were there to be a shortfall, holders of cumulative preferred stock would share ratably in available liquidation assets.




133


Details of preferred stock not subject to mandatory redemption are as follows (in millions except in redemption price and shares):


 

 

 

 

 

Redemption Price

 

Shares Outstanding as of

 

As of December 31,

Series

 

Per Share

December 31, 2014 and 2013

2014 

 

2013 

CL&P

 

 

 

 

 

 

 

 

 

 

 

$

 1.90 

 

Series of 1947

 

$

52.50 

 

163,912 

 

$

 8.2 

 

$

 8.2 

$

 2.00 

 

Series of 1947

 

$

54.00 

 

336,088 

 

 

 16.8 

 

 

 16.8 

$

 2.04 

 

Series of 1949

 

$

52.00 

 

100,000 

 

 

 5.0 

 

 

 5.0 

$

 2.20 

 

Series of 1949

 

$

52.50 

 

200,000 

 

 

 10.0 

 

 

 10.0 

  

 3.90 

%

Series of 1949

 

$

50.50 

 

160,000 

 

 

 8.0 

 

 

 8.0 

$

 2.06 

 

Series E of 1954

 

$

51.00 

 

200,000 

 

 

 10.0 

 

 

 10.0 

$

 2.09 

 

Series F of 1955

 

$

51.00 

 

100,000 

 

 

 5.0 

 

 

 5.0 

  

 4.50 

%

Series of 1956

 

$

50.75 

 

104,000 

 

 

 5.2 

 

 

 5.2 

 

 4.96 

%

Series of 1958

 

$

50.50 

 

100,000 

 

 

 5.0 

 

 

 5.0 

 

 4.50 

%

Series of 1963

 

$

50.50 

 

160,000 

 

 

 8.0 

 

 

 8.0 

 

 5.28 

%

Series of 1967

 

$

51.43 

 

200,000 

 

 

 10.0 

 

 

 10.0 

$

 3.24 

 

Series G of 1968

 

$

51.84 

 

300,000 

 

 

 15.0 

 

 

 15.0 

 

 6.56 

%

Series of 1968

 

$

51.44 

 

200,000 

 

 

 10.0 

 

 

 10.0 

Total CL&P

 

 

 

 

2,324,000 

 

$

 116.2 

 

$

 116.2 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NSTAR Electric

 

 

 

 

 

 

 

 

 

 

 

 

 4.25 

%

Series

 

$

103.625 

 

180,000 

 

$

 18.0 

 

$

 18.0 

 

 4.78 

%

Series

 

$

102.80 

 

250,000 

 

 

 25.0 

 

 

 25.0 

Total NSTAR Electric

 

 

 

 

430,000 

 

$

 43.0 

 

$

 43.0 

Fair Value Adjustment due to Merger with NSTAR

 

 

 

 

 (3.6)

 

 

 (3.6)

Total NU - Preferred Stock of Subsidiaries

 

 

 

$

 155.6 

 

$

 155.6 


18.

COMMON SHAREHOLDERS' EQUITY AND NONCONTROLLING INTERESTS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Noncontrolling

 

 

 

 

Common

 

 

 

 

 

 

 

Interest -

 

 

 

 

Shareholders'

 

Noncontrolling

 

Total

 

Preferred Stock

(Millions of Dollars)

Equity

 

Interest

 

Equity

 

of Subsidiaries

Balance as of January 1, 2012

$

 4,012.7 

 

$

 3.0 

 

$

 4,015.7 

 

$

 116.2 

Net Income

 

 533.1 

 

 

 - 

 

 

 533.1 

 

 

 -  

Purchase Price of NSTAR (1)

 

 5,038.3 

 

 

 - 

 

 

 5,038.3 

 

 

 -  

Other Equity Impacts of Merger with NSTAR (2)

 

 3.4 

 

 

(3.4)

 

 

 -  

 

 

 39.4 

Dividends on Common Shares

 

 (375.5)

 

 

 - 

 

 

 (375.5)

 

 

 -  

Dividends on Preferred Stock

 

 (7.0)

 

 

 - 

 

 

 (7.0)

 

 

 (7.0)

Issuance of Common Shares

 

 13.3 

 

 

 - 

 

 

 13.3 

 

 

 -  

Contributions to NPT

 

 -  

 

 

 0.3 

 

 

 0.3 

 

 

 -  

Other Transactions, Net

 

 21.1 

 

 

 - 

 

 

 21.1 

 

 

 -  

Net Income Attributable to Noncontrolling Interests

 

 (0.1)

 

 

 0.1 

 

 

 -  

 

 

 7.0 

Other Comprehensive Loss

 

 (2.2)

 

 

 - 

 

 

 (2.2)

 

 

 -  

Balance as of December 31, 2012

$

 9,237.1 

 

$

 - 

 

$

 9,237.1 

 

$

 155.6 

Net Income

 

 793.7 

 

 

 - 

 

 

 793.7 

 

 

 -  

Dividends on Common Shares

 

 (462.7)

 

 

 - 

 

 

 (462.7)

 

 

 -  

Dividends on Preferred Stock

 

 (7.7)

 

 

 - 

 

 

 (7.7)

 

 

 (7.7)

Issuance of Common Shares

 

 11.1 

 

 

 - 

 

 

 11.1 

 

 

 -  

Other Transactions, Net

 

 13.2 

 

 

 - 

 

 

 13.2 

 

 

 -  

Net Income Attributable to Noncontrolling Interests

 

 -  

 

 

 - 

 

 

 -  

 

 

 7.7 

Other Comprehensive Income

 

 26.8 

 

 

 - 

 

 

 26.8 

 

 

 -  

Balance as of December 31, 2013

$

 9,611.5 

 

$

 - 

 

$

 9,611.5 

 

$

 155.6 

Net Income

 

 827.1 

 

 

 - 

 

 

 827.1 

 

 

 -  

Dividends on Common Shares

 

 (496.5)

 

 

 - 

 

 

 (496.5)

 

 

 -  

Dividends on Preferred Stock

 

 (7.5)

 

 

 - 

 

 

 (7.5)

 

 

 (7.5)

Issuance of Common Shares

 

 6.6 

 

 

 - 

 

 

 6.6 

 

 

 -  

Other Transactions, Net

 

 63.6 

 

 

 - 

 

 

 63.6 

 

 

 -  

Net Income Attributable to Noncontrolling Interests

 

 -  

 

 

 - 

 

 

 -  

 

 

 7.5 

Other Comprehensive Loss

 

 (28.0)

 

 

 - 

 

 

 (28.0)

 

 

 -  

Balance as of December 31, 2014

$

 9,976.8 

 

$

 - 

 

$

 9,976.8 

 

$

 155.6 


(1)

On April 10, 2012, NU issued approximately 136 million common shares to the NSTAR shareholders in connection with the merger.  See Note 21, "Merger of NU and NSTAR," for further information.


(2)

The preferred stock of NSTAR Electric is not subject to mandatory redemption and has been presented as a noncontrolling interest in NSTAR Electric in NU's financial statements.  In addition, upon completion of the merger, an NSTAR subsidiary that held 25 percent of NPT was merged into EETV, resulting in EETV owning 100 percent of NPT.  Accordingly, the noncontrolling interest balance was eliminated and 100 percent ownership of NPT was reflected in Common Shareholders' Equity.  


For the years ended December 31, 2014, 2013 and 2012, there was no change in ownership of the common equity of CL&P and NSTAR Electric.  




134


19.

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.  For the years ended December 31, 2014, 2013 and 2012, there were 3,643, 1,575 and 4,266, respectively, antidilutive share awards excluded from the computation.  


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


 

 

For the Years Ended December 31,

(Millions of Dollars, except share information)

2014 

 

2013 

 

2012 

Net Income Attributable to Controlling Interest

$

 819.5 

 

$

 786.0 

 

$

 525.9 

 

 

 

 

 

 

 

 

 

 

Weighted Average Common Shares Outstanding:

 

 

 

 

 

 

 

 

 

Basic

 

 316,136,748 

 

 

 315,311,387 

 

 

 277,209,819 

 

Dilutive Effect

 

 1,280,666 

 

 

 899,773 

 

 

 783,812 

 

Diluted

 

 317,417,414 

 

 

 316,211,160 

 

 

 277,993,631 

Basic EPS

$

 2.59 

 

$

 2.49 

 

$

 1.90 

Diluted EPS

$

 2.58 

 

$

 2.49 

 

$

 1.89 


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


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).  


20.

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 years ended December 31, 2014, 2013 and 2012.  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 non-regulated 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.


NSTAR amounts were included in NU beginning April 10, 2012.  




135


NU's segment information is as follows:


 

 

For the Year Ended December 31, 2014

 

 

Electric

 

Natural Gas

 

 

 

 

 

 

 

 

 

 

 

 

(Millions of Dollars)

Distribution

 

Distribution

 

Transmission

 

Other

 

Eliminations

 

Total

Operating Revenues

$

 5,663.4 

 

$

 1,007.3 

 

$

 1,018.2 

 

$

 790.9 

 

$

 (737.9)

 

$

 7,741.9 

Depreciation and Amortization

 

 (384.6)

 

 

 (68.1)

 

 

 (150.5)

 

 

 (42.1)

 

 

 19.9 

 

 

 (625.4)

Other Operating Expenses

 

 (4,366.2)

 

 

 (786.7)

 

 

 (302.1)

 

 

 (748.0)

 

 

 719.3 

 

 

 (5,483.7)

Operating Income

 

 912.6 

 

 

 152.5 

 

 

 565.6 

 

 

 0.8 

 

 

 1.3 

 

 

 1,632.8 

Interest Expense

 

 (191.6)

 

 

 (34.0)

 

 

 (104.1)

 

 

 (36.6)

 

 

 4.2 

 

 

 (362.1)

Interest Income

 

 5.1 

 

 

 - 

 

 

 0.9 

 

 

 3.6 

 

 

 (3.6)

 

 

 6.0 

Other Income, Net

 

 10.7 

 

 

 0.2 

 

 

 10.3 

 

 

 916.0 

 

 

 (918.6)

 

 

 18.6 

Income Tax (Expense)/Benefit

 

 (269.7)

 

 

 (46.4)

 

 

 (174.5)

 

 

 22.3 

 

 

 - 

 

 

 (468.3)

Net Income

 

 467.1 

 

 

 72.3 

 

 

 298.2 

 

 

 906.1 

 

 

 (916.7)

 

 

 827.0 

Net Income Attributable
   to Noncontrolling Interests

 

 (4.7)

 

 

 - 

 

 

 (2.8)

 

 

 - 

 

 

 - 

 

 

 (7.5)

Net Income Attributable
   to Controlling Interest

$

 462.4 

 

$

 72.3 

 

$

 295.4 

 

$

 906.1 

 

$

 (916.7)

 

$

 819.5 

Total Assets (as of)

$

 17,563.4 

 

$

 3,030.9 

 

$

 7,625.6 

 

$

 12,682.5 

 

$

 (11,124.4)

 

$

 29,778.0 

Cash Flows Used for
   Investments in Plant

$

 645.2 

 

$

 176.7 

 

$

 731.6 

 

$

 50.2 

 

$

 - 

 

$

 1,603.7 


 

 

For the Year Ended December 31, 2013

 

 

Electric

 

Natural Gas

 

 

 

 

 

 

 

 

 

 

 

 

(Millions of Dollars)

Distribution

 

Distribution

 

Transmission

 

Other

 

Eliminations

 

Total

Operating Revenues

$

 5,362.3 

 

$

 855.8 

 

$

 978.7 

 

$

 777.5 

 

$

 (673.1)

 

$

 7,301.2 

Depreciation and Amortization

 

 (604.8)

 

 

 (66.7)

 

 

 (136.2)

 

 

 (62.2)

 

 

 10.2 

 

 

 (859.7)

Other Operating Expenses

 

 (3,927.7)

 

 

 (659.4)

 

 

 (281.8)

 

 

 (715.0)

 

 

 671.8 

 

 

 (4,912.1)

Operating Income

 

 829.8 

 

 

 129.7 

 

 

 560.7 

 

 

 0.3 

 

 

 8.9 

 

 

 1,529.4 

Interest Expense

 

 (175.0)

 

 

 (33.1)

 

 

 (100.3)

 

 

 (35.5)

 

 

 5.2 

 

 

 (338.7)

Interest Income

 

 4.1 

 

 

 - 

 

 

 0.7 

 

 

 5.4 

 

 

 (5.6)

 

 

 4.6 

Other Income, Net

 

 12.9 

 

 

 0.8 

 

 

 10.9 

 

 

 858.9 

 

 

 (858.2)

 

 

 25.3 

Income Tax (Expense)/Benefit

 

 (240.0)

 

 

 (36.5)

 

 

 (182.1)

 

 

 31.9 

 

 

 (0.2)

 

 

 (426.9)

Net Income

 

 431.8 

 

 

 60.9 

 

 

 289.9 

 

 

 861.0 

 

 

 (849.9)

 

 

 793.7 

Net Income Attributable
   to Noncontrolling Interests

 

 (4.8)

 

 

 - 

 

 

 (2.9)

 

 

 - 

 

 

 - 

 

 

 (7.7)

Net Income Attributable  
   to Controlling Interest

$

 427.0 

 

$

 60.9 

 

$

 287.0 

 

$

 861.0 

 

$

 (849.9)

 

$

 786.0 

Total Assets (as of)

$

 17,260.0 

 

$

 2,759.7 

 

$

 6,745.8 

 

$

 11,842.4 

 

$

 (10,812.4)

 

$

 27,795.5 

Cash Flows Used for
   Investments in Plant

$

 639.0 

 

$

 168.1 

 

$

 618.5 

 

$

 31.2 

 

$

 - 

 

$

 1,456.8 


 

 

For the Year Ended December 31, 2012

 

 

Electric

 

Natural Gas

 

 

 

 

 

 

 

 

 

 

 

 

(Millions of Dollars)

Distribution

 

Distribution

 

Transmission

 

Other

 

Eliminations

 

Total

Operating Revenues

$

 4,716.5 

 

$

 572.9 

 

$

 861.5 

 

$

 803.8 

 

$

 (680.9)

 

$

 6,273.8 

Depreciation and Amortization

 

 (530.3)

 

 

 (49.1)

 

 

 (109.2)

 

 

 (56.4)

 

 

 4.2 

 

 

 (740.8)

Other Operating Expenses

 

 (3,585.4)

 

 

 (445.2)

 

 

 (251.6)

 

 

 (817.0)

 

 

 684.4 

 

 

 (4,414.8)

Operating Income/(Loss)

 

 600.8 

 

 

 78.6 

 

 

 500.7 

 

 

 (69.6)

 

 

 7.7 

 

 

 1,118.2 

Interest Expense

 

 (165.6)

 

 

 (31.3)

 

 

 (96.7)

 

 

 (43.6)

 

 

 7.3 

 

 

 (329.9)

Interest Income

 

 2.8 

 

 

 - 

 

 

 0.4 

 

 

 7.1 

 

 

 (7.1)

 

 

 3.2 

Other Income, Net

 

 8.9 

 

 

 0.4 

 

 

 7.3 

 

 

 795.0 

 

 

 (795.1)

 

 

 16.5 

Income Tax (Expense)/Benefit

 

 (150.2)

 

 

 (16.9)

 

 

 (159.2)

 

 

 55.5 

 

 

 (4.1)

 

 

 (274.9)

Net Income

 

 296.7 

 

 

 30.8 

 

 

 252.5 

 

 

 744.4 

 

 

 (791.3)

 

 

 533.1 

Net Income Attributable
   to Noncontrolling Interests

 

 (4.4)

 

 

 - 

 

 

 (2.8)

 

 

 - 

 

 

 - 

 

 

 (7.2)

Net Income Attributable
   to Controlling Interest

$

 292.3 

 

$

 30.8 

 

$

 249.7 

 

$

 744.4 

 

$

 (791.3)

 

$

 525.9 

Cash Flows Used for
   Investments in Plant

$

611.7 

 

$

148.7 

 

$

663.6 

 

$

48.3 

 

$

 - 

 

$

 1,472.3 


21.

MERGER OF NU AND NSTAR


On April 10, 2012, NU acquired 100 percent of the outstanding common shares of NSTAR.  Pursuant to the terms and conditions of the Agreement and Plan of Merger, as amended, (the "Merger Agreement,") NSTAR and its subsidiaries became wholly-owned subsidiaries of NU.


NSTAR was a holding company engaged through its subsidiaries in the energy delivery business serving electric and natural gas distribution customers in Massachusetts.  As part of the merger, NSTAR shareholders received 1.312 NU common shares for each NSTAR common share owned (the "exchange ratio") as of the acquisition date.  NU issued approximately 136 million common shares to the NSTAR shareholders as a result of the merger.  




136


Purchase Price:  Pursuant to the merger, all of the NSTAR common shares were exchanged at the fixed exchange ratio of 1.312 NU common shares for each NSTAR common share.  The total consideration transferred in the merger was based on the closing price of NU common shares on April 9, 2012, the day prior to the date the merger was completed, and was calculated as follows:


NSTAR common shares outstanding as of April 9, 2012 (in thousands)*

 

 103,696 

Exchange ratio

 

1.312 

NU common shares issued for NSTAR common shares outstanding (in thousands)

 

 136,049 

Closing price of NU common shares on April 9, 2012

$

36.79 

Value of common shares issued (in millions)

$

 5,005 

Fair value of NU replacement stock-based compensation awards related to

   pre-merger service (in millions)

 

33 

Total purchase price (in millions)

$

 5,038 


*

Included 109 thousand shares related to NSTAR stock-based compensation awards that vested immediately prior to the merger.


Certain of NSTAR's stock-based compensation awards, including deferred shares, performance shares and all outstanding stock options, were replaced with NU awards using the exchange ratio upon consummation of the merger.  In accordance with accounting guidance for business combinations, the portion of the fair value of these awards attributable to service provided prior to the merger was included in the purchase price as it represented consideration transferred in the merger.  See Note 9C, "Employee Benefits – Share-Based Payments," for further information.


Purchase Price Allocation:  The allocation of the total purchase price to the estimated fair values of the assets acquired and liabilities assumed was determined based on the accounting guidance for fair value measurements.  The allocation of the total purchase price included adjustments to record the fair value of NSTAR's unregulated telecommunications business, regulatory assets not earning a return, lease agreements, long-term debt and the preferred stock of NSTAR Electric.  The fair values of NSTAR's assets and liabilities were determined based on significant estimates and assumptions, including Level 3 inputs, that were judgmental in nature.  These estimates and assumptions included the timing and amounts of projected future cash flows and discount rates reflecting risk inherent in future cash flows.  


In accordance with accounting guidance for business combinations, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill.  


The goodwill from the merger with NSTAR totaled $3.2 billion and was allocated to NU's reporting units based on their estimated fair values.  See Note 22, "Goodwill," for the allocation of goodwill to each reporting unit.   


Pro Forma Financial Information:  The following unaudited pro forma financial information reflects the pro forma combined results of operations of NU and NSTAR and reflects the amortization of purchase price adjustments assuming the merger had taken place on January 1, 2011.  The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of NU.  


(Pro forma amounts in millions, except per share amounts)

For the Year Ended December 31, 2012

Operating Revenues

$

7,004 

Net Income Attributable to Controlling Interest

 

630 

Basic EPS

 

2.00 

Diluted EPS

 

1.99 


Pro forma net income does not include potential cost savings associated with the merger.  Pro forma net income also excludes certain non-recurring merger costs and costs related to the Connecticut and Massachusetts merger settlement agreements described below, with the following aggregate after-tax impacts:


(Millions of Dollars)

For the Year Ended December 31, 2012

Transaction and Other Costs

$

 32 

Settlement Agreement Impacts

 

 60 

Total After-Tax Non-Recurring Costs Excluded from

   Pro Forma Net Income Attributable to Controlling Interest

$

 92 


Regulatory Approvals:  On February 15, 2012, NU and NSTAR reached comprehensive merger settlement agreements with the Massachusetts Attorney General and the DOER.  The Attorney General settlement agreement covered a variety of rate-making and rate design issues, including a base distribution rate freeze through 2015 for NSTAR Electric, NSTAR Gas and WMECO and $15 million, $3 million and $3 million in the form of rate credits to their respective customers.  On April 4, 2012, the DPU approved the settlement agreements and the merger of NU and NSTAR.


On March 13, 2012, NU and NSTAR reached a comprehensive merger settlement agreement with both the Connecticut Attorney General and the Connecticut Office of Consumer Counsel.  The settlement agreement covered a variety of matters, including a $25 million rate credit to CL&P customers, a CL&P base distribution rate freeze until December 1, 2014, and the establishment of a $15 million fund for energy efficiency and other initiatives to be disbursed at the direction of the DEEP.  In the agreement, CL&P agreed to forego rate recovery of $40 million of the deferred storm restoration costs associated with restoration activities following Tropical Storm Irene and the October 2011 snowstorm.  On April 2, 2012, the PURA approved the settlement agreement and the merger of NU and NSTAR.




137


The pre-tax financial impacts of the Connecticut and Massachusetts merger settlement agreements that were recognized in 2012 by NU, CL&P, NSTAR Electric, and WMECO are summarized as follows:


(Millions of Dollars)

NU

 

CL&P

 

NSTAR Electric

 

WMECO

Customer Rate Credits

$

 46 

 

$

 25 

 

$

15 

 

$

Storm Costs Deferral Reduction

 

 40 

 

 

 40 

 

 

 -   

 

 

 -   

Establishment of Energy Efficiency Fund

 

 15 

 

 

 -   

 

 

 -   

 

 

 -   

Total Pre-Tax Settlement Agreement Impacts

$

 101 

 

$

 65 

 

$

 15 

 

$

 3 


22.

GOODWILL


In accordance with the accounting standards, goodwill is not subject to amortization.  However, goodwill is subject to fair value-based rules for measuring impairment, and resulting write-downs, if any, are charged to Operating Expenses.  These accounting standards require that goodwill be reviewed at least annually for impairment and whenever facts or circumstances indicate that there may be an impairment.  NU uses October 1st as the annual goodwill impairment testing date.  


On April 10, 2012, upon consummation of the merger with NSTAR, NU recorded approximately $3.2 billion of goodwill.  With the completion of the merger, NU reviewed its management structure and determined that the reporting units for the purpose of testing goodwill for impairment are Electric Distribution, Electric Transmission and Natural Gas Distribution.  NU's reporting units are consistent with the operating segments underlying the reportable segments identified in Note 20, "Segment Information," to the financial statements.  Accordingly, the goodwill resulting from the merger was allocated to the Electric Distribution, Electric Transmission and Natural Gas Distribution reporting units based on the estimated fair values of the reporting units as of the merger date.


Prior to the merger with NSTAR, the only reporting unit that maintained goodwill was the Natural Gas Distribution reportable segment related to the acquisition of the parent of Yankee Gas in 2000.  This goodwill was recorded at Yankee Gas.  The goodwill balance at Yankee Gas as of December 31, 2014 and 2013 was $0.3 billion.


NU completed its annual goodwill impairment test for each of its reporting units as of October 1, 2014 and determined that no impairment exists.  There were no events subsequent to October 1, 2014 that indicated impairment of goodwill.


There were no changes to the goodwill balance or the allocation of goodwill as of December 31, 2014 or 2013.  The allocation of goodwill to NU's reporting units as of both December 31, 2014 and 2013 was as follows:


 

 

 

Electric

 

Electric

 

Natural Gas

 

 

 

(Billions of Dollars)

 

Distribution

 

Transmission

 

Distribution

 

Total

Goodwill Allocation

 

$

2.5 

 

$

0.6 

 

$

0.4 

 

$

3.5 


23.

VARIABLE INTEREST ENTITIES


The Company's variable interests outside of the consolidated group are not material and consist of contracts that are required by regulation and provide for regulatory recovery of contract costs and benefits through customer rates.  NU, CL&P and NSTAR Electric hold variable interests in variable interest entities (VIEs) through agreements with certain entities that own single renewable energy or peaking generation power plants and with other independent power producers.  NU, CL&P and NSTAR Electric do not control the activities that are economically significant to these VIEs or provide financial or other support to these VIEs.  Therefore, NU, CL&P and NSTAR Electric do not consolidate any power plant VIEs.  


24.

QUARTERLY FINANCIAL DATA (UNAUDITED)


NU Consolidated Statements of Quarterly Financial Data

Quarter Ended

(Millions of Dollars, except per share information)

March 31,

 

June 30,

 

September 30,

 

December 31,

2014 

 

 

 

 

 

 

 

 

 

 

 

  Operating Revenues

$

 2,290.6 

 

$

 1,677.6 

 

$

 1,892.5 

 

$

 1,881.2 

  Operating Income

 

 467.7 

 

 

 294.0 

 

 

 440.9 

 

 

 430.2 

  Net Income

 

 237.8 

 

 

 129.2 

 

 

 236.5 

 

 

 223.6 

  Net Income Attributable to Controlling Interest

 

 236.0 

 

 

 127.4 

 

 

 234.6 

 

 

 221.5 

  Basic EPS (a)

$

 0.75 

 

$

 0.40 

 

$

 0.74 

 

$

 0.69 

  Diluted EPS (a)

$

 0.74 

 

$

 0.40 

 

$

 0.74 

 

$

 0.69 

 

 

 

 

 

 

 

 

 

 

 

 

2013 

 

 

 

 

 

 

 

 

 

 

 

  Operating Revenues

$

 1,995.0 

 

$

 1,635.9 

 

$

 1,892.6 

 

$

 1,777.7 

  Operating Income

 

 418.9 

 

 

 350.6 

 

 

 399.3 

 

 

 360.6 

  Net Income

 

 230.0 

 

 

 173.1 

 

 

 211.4 

 

 

 179.2 

  Net Income Attributable to Controlling Interest

 

 228.1 

 

 

 171.0 

 

 

209.5 

 

 

 177.4 

  Basic and Diluted EPS (a)

$

 0.72 

 

$

 0.54 

 

$

0.66 

 

$

 0.56 

 

 

 

 

 

 

 

 

 

 

 

 

(a)  The summation of quarterly EPS data may not equal annual data due to rounding.

 

 

 

 

 

 

 

 

 

 

 

 




138






Statements of Quarterly Financial Data

Quarter Ended

(Millions of Dollars)

March 31,

 

June 30,

 

September 30,

 

December 31,

CL&P

 

 

 

 

 

 

 

 

 

 

 

2014 

 

 

 

 

 

 

 

 

 

 

 

  Operating Revenues

$

 734.6 

 

$

 587.3 

 

$

 695.6 

 

$

 675.1 

  Operating Income

 

 158.0 

 

 

 92.1 

 

 

 146.2 

 

 

 159.0 

  Net Income

 

 79.3 

 

 

 37.4 

 

 

 83.9 

 

 

 87.2 

 

 

 

 

 

 

 

 

 

 

 

 

2013 

 

 

 

 

 

 

 

 

 

 

 

  Operating Revenues

$

 624.1 

 

$

 569.3 

 

$

 648.4 

 

$

 600.5 

  Operating Income

 

 149.7 

 

 

 136.8 

 

 

 133.9 

 

 

 119.2 

  Net Income

 

 85.0 

 

 

 67.9 

 

 

 66.3 

 

 

 60.2 

 

 

 

 

 

 

 

 

 

 

 

 

NSTAR Electric

 

 

 

 

 

 

 

 

 

 

 

2014 

 

 

 

 

 

 

 

 

 

 

 

  Operating Revenues

$

 666.2 

 

$

 561.5 

 

$

 727.9 

 

$

 581.1 

  Operating Income

 

 118.4 

 

 

 121.5 

 

 

 206.6 

 

 

 132.0 

  Net Income

 

 58.1 

 

 

 60.1 

 

 

 115.6 

 

 

 69.3 

 

 

 

 

 

 

 

 

 

 

 

 

2013 

 

 

 

 

 

 

 

 

 

 

 

  Operating Revenues

$

 592.3 

 

$

 570.4 

 

$

 753.9 

 

$

 576.9 

  Operating Income

 

 94.5 

 

 

 112.5 

 

 

 192.0 

 

 

 109.2 

  Net Income

 

 48.1 

 

 

 58.0 

 

 

 107.0 

 

 

 55.4 

 

 

 

 

 

 

 

 

 

 

 

 

PSNH

 

 

 

 

 

 

 

 

 

 

 

2014 

 

 

 

 

 

 

 

 

 

 

 

  Operating Revenues

$

 299.8 

 

$

 211.6 

 

$

 223.7 

 

$

 224.4 

  Operating Income

 

 64.0 

 

 

 49.0 

 

 

 56.4 

 

 

 60.0 

  Net Income

 

 32.6 

 

 

 24.1 

 

 

 28.2 

 

 

 29.0 

 

 

 

 

 

 

 

 

 

 

 

 

2013 

 

 

 

 

 

 

 

 

 

 

 

  Operating Revenues

$

 273.8 

 

$

 216.1 

 

$

 218.6 

 

$

 226.9 

  Operating Income

 

 58.1 

 

 

 54.3 

 

 

 56.6 

 

 

 56.2 

  Net Income

 

 29.0 

 

 

 27.2 

 

 

 28.4 

 

 

 26.8 

 

 

 

 

 

 

 

 

 

 

 

 

WMECO

 

 

 

 

 

 

 

 

 

 

 

2014 

 

 

 

 

 

 

 

 

 

 

 

  Operating Revenues

$

 137.4 

 

$

 108.3 

 

$

 118.1 

 

$

 129.6 

  Operating Income

 

 34.7 

 

 

 17.7 

 

 

 31.2 

 

 

 34.0 

  Net Income

 

 18.1 

 

 

 7.0 

 

 

 14.7 

 

 

 18.0 

 

 

 

 

 

 

 

 

 

 

 

 

2013 

 

 

 

 

 

 

 

 

 

 

 

  Operating Revenues

$

 125.0 

 

$

 115.0 

 

$

 121.8 

 

$

110.9 

  Operating Income

 

 35.6 

 

 

 32.4 

 

 

 28.9 

 

 

 22.4 

  Net Income

 

 18.6 

 

 

 16.4 

 

 

 15.0 

 

 

 10.4 




139


Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure


No events that would be described in response to this item have occurred with respect to NU, CL&P, NSTAR Electric, PSNH or WMECO.


Item 9A.

Controls and Procedures


Management, on behalf of NU, CL&P, NSTAR Electric, PSNH and WMECO, is responsible for the preparation, integrity, and fair presentation of the accompanying Consolidated Financial Statements and other sections of this combined Annual Report on Form 10-K.  NU's internal controls over financial reporting were audited by Deloitte & Touche LLP.    


Management, on behalf of NU, CL&P, NSTAR Electric, PSNH and WMECO, is responsible for establishing and maintaining adequate internal controls over financial reporting.  The internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.  There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business.  Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment.  Under the supervision and with the participation of the principal executive officer and principal financial officer, an evaluation of the effectiveness of internal controls over financial reporting was conducted based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting at NU, CL&P, NSTAR Electric, PSNH and WMECO were effective as of December 31, 2014.


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 December 31, 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 officer and principal financial officer as of the end of the period covered by this Annual Report on Form 10-K.  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 officer 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 officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosures.


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.  


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 December 31, 2014 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.


Item 9B.

Other Information


No information is required to be disclosed under this item as of December 31, 2014, as this information has been previously disclosed in applicable reports on Form 8-K during the fourth quarter of 2014.




140


Item 10.

Directors, Executive Officers and Corporate Governance


The information in Item 10 is provided as of February 18, 2015, except where otherwise indicated.


Certain information required by this Item 10 is omitted for NSTAR Electric, PSNH and WMECO pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly Owned Subsidiaries.


NU


In addition to the information provided below concerning the executive officers of NU, incorporated herein by reference is the information to be contained in the sections captioned "Election of Trustees," "Governance of Northeast Utilities" and the related subsections, "Selection of Trustees," and "Section 16(a) Beneficial Ownership Reporting Compliance" of NU's definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about March 13, 2015.  


NU and CL&P


Each member of CL&P's Board of Directors is an employee of CL&P, NU or an affiliate.  Directors are elected annually to serve for one year until their successors are elected and qualified.  


Set forth below is certain information as of February 18, 2015 concerning CL&P's Directors and NU's and CL&P's executive officers:  


Name

 

Age

 

Title

Thomas J. May

 

67

 

Chairman of the Board, President and Chief Executive Officer of NU and NUSCO; Chairman and a Director of the Regulated companies, including CL&P

James J. Judge

 

59

 

Executive Vice President and Chief Financial Officer of NU and Executive Vice President and Chief Financial Officer and a Director of NUSCO and the Regulated companies, including CL&P

David R. McHale 1

 

54

 

Executive Vice President and Chief Administrative Officer of NU and  NUSCO

Leon J. Olivier

 

66

 

Executive Vice President-Enterprise Energy Strategy and Business Development of NU and NUSCO

Werner J. Schweiger

 

55

 

Executive Vice President and Chief Operating Officer of NU and NUSCO; Chief Executive Officer and a Director of the Regulated companies, including CL&P

Gregory B. Butler

 

57

 

Senior Vice President and General Counsel of NU and NUSCO; Senior Vice President and General Counsel and a Director of the Regulated companies, including CL&P

Christine M. Carmody 2

 

52

 

Senior Vice President-Human Resources of NUSCO

Joseph R. Nolan, Jr. 2

 

51

 

Senior Vice President-Corporate Relations of NUSCO

William P. Herdegen III 3

 

60

 

President and Chief Operating Officer of CL&P

Jay S. Buth

 

45

 

Vice President, Controller and Chief Accounting Officer of NU, NUSCO and the Regulated companies, including CL&P  


1

Deemed an executive officer of CL&P pursuant to Rule 3b-7 under the Securities Exchange Act of 1934.

2

Deemed an executive officer of NU and CL&P pursuant to Rule 3b-7 under the Securities Exchange Act of 1934.

3

Mr. Herdegen is the President and Chief Operating Officer of CL&P and is therefore an executive officer solely of CL&P.


Thomas J. May.  Mr. May has served as Chairman of the Board of NU since October 10, 2013, and as President and Chief Executive Officer and as a Trustee of NU; as Chairman and a Director of CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO and Yankee Gas; and as Chairman, President and Chief Executive Officer and a Director of NUSCO since April 10, 2012.  Mr. May has served as a Director of NSTAR Electric and NSTAR Gas since September 27, 1999.  Mr. May previously served as Chairman, President and Chief Executive Officer and a Trustee of NSTAR, and as Chairman, President and Chief Executive Officer of NSTAR Electric and NSTAR Gas until April 10, 2012.  He served as Chairman, Chief Executive Officer and a Trustee since NSTAR was formed in 1999, and was elected President in 2002.  Mr. May has served as Chairman of the Board of Eversource Energy Foundation, Inc. since October 15, 2013, and as a Director of Eversource Energy Foundation, Inc. since April 10, 2012.  He previously served as President of Eversource Energy Foundation, Inc. from October 15, 2013 to September 29, 2014.  He has served as a Trustee of the NSTAR Foundation since August 18, 1987.  


James J. Judge.  Mr. Judge has served as Executive Vice President and Chief Financial Officer of NU, CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO, Yankee Gas and NUSCO and as a Director of CL&P, PSNH, WMECO, Yankee Gas and NUSCO since April 10, 2012 and of NSTAR Electric and NSTAR Gas since September 27, 1999.  Previously, Mr. Judge served as Senior Vice President and Chief Financial Officer of NSTAR, NSTAR Electric and NSTAR Gas from 1999 until April 2012.  Mr. Judge has served as Treasurer and as a Director of Eversource Energy Foundation, Inc. since April 10, 2012.  He has served as a Trustee of the NSTAR Foundation since December 12, 1995.  


David R. McHale.  Mr. McHale has served as Executive Vice President and Chief Administrative Officer of NU and NUSCO since April 10, 2012 and as a Director of NUSCO since January 1, 2005.  Mr. McHale previously served as Executive Vice President and Chief Administrative Officer of CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO and Yankee Gas from April 10, 2012 to September 29, 2014 and as a Director of NSTAR Electric and NSTAR Gas from November 27, 2012 to September 29, 2014, of PSNH, WMECO and Yankee Gas from January 1, 2005 to September 29, 2014, and of CL&P from January 15, 2007 to September 29, 2014.  Previously, Mr. McHale served as Executive Vice President and



141


Chief Financial Officer of NU, CL&P, PSNH, WMECO, Yankee Gas and NUSCO from January 2009 to April 2012, and as Senior Vice President and Chief Financial Officer of NU, CL&P, PSNH, WMECO, Yankee Gas and NUSCO from January 2005 to December 2008.  He has served as a Director of Eversource Energy Foundation, Inc. since January 1, 2005.  Mr. McHale has served as a Trustee of the NSTAR Foundation since April 10, 2012.  


Leon J. Olivier.  Mr. Olivier has served as Executive Vice President-Enterprise Energy Strategy and Business Development of NU since September 2, 2014 and as a Director of NUSCO since January 17, 2005.  Mr. Olivier previously served as Executive Vice President and Chief Operating Officer of NU and NUSCO from May 13, 2008 until September 2, 2014, and as Chief Executive Officer of NSTAR Electric and NSTAR Gas from April 10, 2012 until August 11, 2014, of CL&P, PSNH, WMECO and Yankee Gas from January 15, 2007 to September 29, 2014, and of CL&P from September 10, 2001 to September 29, 2014, and as a Director of NSTAR Electric and NSTAR Gas from November 27, 2012 to September 29, 2014, of PSNH, WMECO and Yankee Gas from January 17, 2005 to September 29, 2014, and of CL&P from September 10, 2001 to September 29, 2014.   Previously, Mr. Olivier served as Executive Vice President-Operations of NU from February 13, 2007 to May 12, 2008.  He has served as a Director of Eversource Energy Foundation, Inc. since April 1, 2006.  Mr. Olivier has served as a Trustee of the NSTAR Foundation since April 10, 2012.  


Werner J. Schweiger.  Mr. Schweiger has served as Executive Vice President and Chief Operating Officer of NU since September 2, 2014 and of NUSCO since August 11, 2014, and as Chief Executive Officer of CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO and Yankee Gas since August 11, 2014, and as a Director of NUSCO, NSTAR Gas and Yankee Gas since September 29, 2014 and of CL&P, PSNH, NSTAR Electric and WMECO since May 28, 2013.  He previously served as President-Electric Distribution of NUSCO from January 16, 2013 until August 11, 2014 and as President of NSTAR Electric from April 10, 2012 until January 16, 2013 and as a Director of NSTAR Electric from November 27, 2012 to January 16, 2013.  From February 27, 2002 until April 10, 2012, Mr. Schweiger was Senior Vice President-Operations of NSTAR Electric and NSTAR Gas.  Mr. Schweiger has served as a Director of Eversource Energy Foundation, Inc. since September 29, 2014.  He has served as a Trustee of the NSTAR Foundation since April 25, 2002.


Gregory B. Butler.  Mr. Butler has served as Senior Vice President and General Counsel of NU since May 1, 2014, of NSTAR Electric, and NSTAR Gas since April 10, 2012, and of CL&P, PSNH, WMECO, Yankee Gas and NUSCO since March 9, 2006.  Mr. Butler has served as a Director of NSTAR Electric and NSTAR Gas since April 10, 2012, of NUSCO since November 27, 2012, and of CL&P, PSNH, WMECO and Yankee Gas since April 22, 2009.  Mr. Butler previously served as Senior Vice President, General Counsel and Secretary of NU from April 10, 2012 until May 1, 2014, and as Senior Vice President and General Counsel of NU from December 1, 2005 to April 10, 2012.  He has served as a Director of Eversource Energy Foundation, Inc. since December 1, 2002.


Christine M. Carmody.  Ms. Carmody has served as Senior Vice President-Human Resources of NUSCO since April 10, 2012 and as a Director of NUSCO since November 27, 2012.  Ms. Carmody previously served as Senior Vice President-Human Resources of CL&P, PSNH, WMECO and Yankee Gas from November 27, 2012 to September 29, 2014, and of NSTAR Electric and NSTAR Gas from August 1, 2008 to September 29, 2014, and as a Director of CL&P, PSNH, WMECO and Yankee Gas from April 10, 2012 to September 29, 2014 and of NSTAR Electric and NSTAR Gas from November 27, 2012 to September 29, 2014.  Previously, Ms. Carmody served as Vice President-Organizational Effectiveness of NSTAR, NSTAR Electric and NSTAR Gas from June 2006 to August 2008.  Ms. Carmody has served as a Director of Eversource Energy Foundation, Inc. since April 10, 2012.  She has served as a Trustee of the NSTAR Foundation since August 1, 2008.


Joseph R. Nolan, Jr.  Mr. Nolan has served as Senior Vice President-Corporate Relations of NUSCO since April 10, 2012 and as a Director of NUSCO since November 27, 2012.  Mr. Nolan previously served as Senior Vice President-Corporate Relations of NSTAR Electric and NSTAR Gas from April 10, 2012 to September 29, 2014, and of CL&P, PSNH, WMECO and Yankee Gas from November 27, 2012 to September 29, 2014, as a Director of CL&P, PSNH, WMECO and Yankee Gas from April 10, 2012 to September 29, 2014 and of NSTAR Electric and NSTAR Gas from November 27, 2012 to September 29, 2014.  Previously, Mr. Nolan served as Senior Vice President-Customer & Corporate Relations of NSTAR, NSTAR Electric and NSTAR Gas from 2006 until April 10, 2012.  Mr. Nolan has served as a Director of Eversource Energy Foundation, Inc. since April 10, 2012, and has served as Executive Director of Eversource Energy Foundation, Inc. since October 15, 2013.  He has served as a Trustee of the NSTAR Foundation since October 1, 2000.


William P. Herdegen III.  Mr. Herdegen has served as President and Chief Operating Officer of CL&P since September 11, 2012 and as a Director of CL&P from September 11, 2012 to September 29, 2014.  Previously, Mr. Herdegen served as Vice President of Transmission and Distribution Engineering and Operations for Kansas City Power & Light Company from 2008 until his retirement on September 7, 2012; as Vice President, Distribution and Customer Operations from 2005 to 2008; and as Vice President, Distribution Operations from 2001 to 2005.  Mr. Herdegen began his utility career at Commonwealth Edison, where he held various positions, including Vice President, Engineering, Construction and Maintenance, corporate project manager, operations manager, business unit supply manager, district manager, and field engineer.


Jay S. Buth.  Mr. Buth has served as Vice President, Controller and Chief Accounting Officer of NU, CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO, Yankee Gas and NUSCO since April 10, 2012.  Previously, Mr. Buth served as Vice President-Accounting and Controller of NU, CL&P, PSNH, WMECO, Yankee Gas and NUSCO from June 2009 until April 10, 2012.  From June 2006 through January 2009, Mr. Buth served as the Vice President and Controller for New Jersey Resources Corporation, an energy services holding company that provides natural gas and wholesale energy services, including transportation, distribution and asset management.


There are no family relationships between any director or executive officer and any other trustee, director or executive officer of NU or CL&P and none of the above executive officers or directors serves as an executive officer or director pursuant to any agreement or understanding with any other person.  Our executive officers hold the offices set forth opposite their names until the next annual meeting of the Board of Trustees, in the case of NU, and the Board of Directors, in the case of CL&P, and until their successors have been elected and qualified.  




142


CL&P obtains audit services from the independent registered public accounting firm engaged by the Audit Committee of NU's Board of Trustees.  CL&P does not have its own audit committee or, accordingly, an audit committee financial expert.  CL&P relies on NU's audit committee and the audit committee financial expert.  


CODE OF ETHICS AND STANDARDS OF BUSINESS CONDUCT


Each of NU, CL&P, NSTAR Electric, PSNH and WMECO has adopted a Code of Ethics for Senior Financial Officers (Chief Executive Officer, Chief Financial Officer and Controller) and the Code of Business Conduct, which are applicable to all Trustees, directors, officers, employees, contractors and agents of NU, CL&P, NSTAR Electric, PSNH and WMECO.  The Code of Ethics and the Code of Business Conduct have both been posted on the NU web site and are available at www.eversource.com/investors/corporate_gov/default.asp on the Internet.  Any amendments to or waivers from the Code of Ethics and Code of Business Conduct for executive officers, directors or Trustees will be posted on the website.  Any such amendment or waiver would require the prior consent of the Board of Trustees or an applicable committee thereof.


Printed copies of the Code of Ethics and the Code of Business Conduct are also available to any shareholder without charge upon written request mailed to:


Richard J. Morrison

Secretary

Eversource Energy

P.O. Box 270

Hartford, CT 06141




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Item 11.

Executive Compensation


NU


The information required by this Item 11 for NU is incorporated herein by reference to certain information contained in NU's definitive proxy statement for solicitation of proxies, which is expected to be filed with the SEC on or about March 13, 2015, under the sections captioned "Compensation Discussion and Analysis," plus related subsections, and "Compensation Committee Report," plus related subsections following such Report.


NSTAR ELECTRIC, PSNH and WMECO


Certain information required by this Item 11 has been omitted for NSTAR Electric, PSNH and WMECO pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly Owned Subsidiaries.


CL&P


The information in this Item 11 relates solely to CL&P.


COMPENSATION DISCUSSION AND ANALYSIS


CL&P is a wholly-owned subsidiary of NU.  Its board of directors consists entirely of executive officers of NU.  CL&P does not have a compensation committee, and the Compensation Committee of NU's Board of Trustees determines compensation for the executive officers of CL&P, including their salaries, annual incentive awards and long-term incentive awards.  All of CL&P's "Named Executive Officers," as defined below, also serve as officers of NU and one or more other subsidiaries of NU.  Compensation set by the Compensation Committee of NU (the "Committee") and set forth herein is for services rendered to NU and its subsidiaries by such officers in all capacities.


The purpose of this Compensation Discussion and Analysis is to provide information about NU's compensation objectives, plans, policies and actions for the Named Executive Officers.  The discussion describes the specific components of the compensation program, how NU measures performance, and how compensation awards and decisions were made by the Compensation Committee for the Named Executive Officers, as presented in the tables and narratives that follow.  While this discussion focuses primarily on 2014 information, it also addresses decisions that were made in other periods to the extent that these decisions are relevant to the full understanding of NU's compensation program and the specific awards that were made in 2014 and early 2015.


Business Highlights


Since the merger with NSTAR in 2012, NU has continued to meet its commitment of achieving above-average earnings and dividend growth.


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Note 1:

2012-2014 recurring earnings per share have grown 7.9%, consistent with NU's guidance and well above the industry average.  Recurring earnings per share presented above for all years exclude merger-related costs.  A reconciliation between reported earnings per share and the recurring earnings per share presented above appears under the caption "Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview" in this Annual Report on Form 10-K.


Note 2:

The NU Board of Trustees increased the annual dividend rate by 6.8 percent for 2014 to $1.57 per share, exceeding the Edison Electric Institute (EEI) Index dividend growth rate of 3.7%.  2012-2014 dividends have grown 7.0%, in line with NU's earnings per share growth and well ahead of the industry average.




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NU's Total Shareholder Return for the one-year and five-year periods has outperformed both the EEI Index and the S&P 500.  NU's market capitalization at the end of 2014 grew to $17 billion, increasing shareholder value by over $8 billion in the 33-month period following the 2012 merger with NSTAR.  NU commenced trading under the symbol "ES" on February 19, 2015.


Note 1:

An investment of $1,000 in NU common shares at the beginning of the one-year period commencing January 1, 2014 was worth $1,305 on December 31, 2014.


Note 2:

An investment of $1,000 in NU common shares at the beginning of the five-year period commencing January 1, 2010 was worth $2,458 on December 31, 2014.


NU's operating performance continues to improve each year.  This is the result of the ongoing implementation of best practices, focused spending on reliability improvements to reduce the number and length of outages, and performing work safely each and every day.


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Note 1:

Reliability as measured by months between interruptions has improved significantly; on average, NU's customers experienced an outage every 15.4 months during 2014 vs. 11.9 months in 2011.


Note 2:

The average time to restore power has decreased significantly, from 120.5 minutes in 2011 to 82.0 minutes in 2014.


Note 3:

Safety performance measured by the days away or restricted time per 100 workers has improved significantly, to 1.44 in 2014 from 2.58 in 2011.




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Summary of 2014 Performance


In 2014, NU achieved excellent financial and operational performance results. NU met or exceeded each of the challenging financial and operational goals established by the Committee at the beginning of 2014 and had the best system reliability results in NU's history.  The following is a summary of some of NU's most important accomplishments in 2014:


Financial Accomplishments


NU's 2014 recurring earnings were $2.65 per share, excluding merger related costs, a 4.7 percent increase over 2013 results.


NU continued to achieve operating and maintenance expense reductions through successful integration activities, exceeding  the goal of a greater than 3 percent reduction in operating expenses from 2013. Operating costs were 6.8 percent, or $101 million, lower than 2013.


NU increased its dividend to $1.57 per share, a 6.8 percent increase over 2013, continuing to significantly outperform the industry average.


NU delivered 30.5 percent total shareholder return in 2014, the sixth consecutive year of double digit total shareholder return, creating $8 billion in NU shareholder value in the 33-month period following NU's 2012 merger with NSTAR.


 

Total Shareholder Return

 

2014

3-Year

5-Year

10-Year

ES

30.5%

64.3%

145.8%

297.7%

EEI Index

28.9%

48.7%

91.0%

156.0%

S&P 500

13.7%

74.6%

105.1%

109.4%


Operational Accomplishments


NU's overall electric system performance in 2014 was the best on record and represents top quartile industry performance.


NU's Massachusetts subsidiaries, NSTAR Electric Company, NSTAR Gas Company and Western Massachusetts Electric Company, paid no penalties for Service Quality Index performance in 2014 under regulations in Massachusetts, which is the only state NU serves that has specific performance targets.


NU continued the focus on streamlining and fully integrating business processes across the company, including standardizing system design, equipment and operating and maintenance practices and implementing a new financial accounting and budgeting system in a well controlled and timely manner.


NU exceeded established goals in calls answered on-time, safety performance, and response to gas service calls.


Achievement of the 2014 performance goals and additional accomplishments and the Committee's assessment of company and executive performance are more fully described in the section titled "2014 Annual Incentive Program."  Specific decisions regarding executive compensation based upon the Committee's assessment of company and executive performance and market data are described in this Compensation Discussion and Analysis ("CD&A") below.


Pay for Performance


The Committee follows a philosophy of linking the Named Executive Officers' compensation to performance that will ultimately benefit customers and shareholders.  The intent of NU's compensation program is to attract and retain the best executive talent, motivate the executives to meet or exceed specific stretch financial and operational goals set each year, and compensate the executives in a manner that aligns compensation directly with performance.  NU strives to provide executives with base salary, performance-based annual incentive compensation and long-term incentive compensation opportunities that are competitive with market practices and that reward excellent performance.  


Executive Compensation Governance


The Committee annually assesses the independence of its compensation consultant, Pay Governance LLC (Pay Governance), which is retained directly by the Committee, performs no other consulting or other services for the company, and has no relationship with the company that could result in a conflict of interest.  The Committee has concluded that Pay Governance is independent and that no conflict of interest exists between Pay Governance and the company.


NU's executive and Trustee share ownership and holding guidelines noted in this CD&A emphasize the importance of share ownership.  In addition to the share ownership guidelines requirement, NU requires its executives to hold the net shares awarded under the company's stock compensation program until the share ownership guidelines requirement has been met.  In addition, 100% of Trustee stock compensation is deferred and not distributed until the Trustee's retirement from the Board.




146


The Committee has a policy that would require NU's employees to reimburse the company for incentive compensation received if earnings were subsequently required to be restated as a result of noncompliance with accounting rules caused by fraud or misconduct.  


NU has discontinued the use of "gross-ups" in all new or materially amended executive compensation agreements.


The Committee has a policy prohibiting all Trustees and employees from purchasing financial instruments or otherwise entering into any transactions that are designed to have the effect of hedging or offsetting any decrease in the market value of NU common shares.  This policy also prohibits all pledging, derivative transactions or short sales involving NU common shares or the holding of any NU common shares in a margin account.


Employment agreements provide for "double trigger" change of control acceleration of awards assumed by the surviving company.  


NAMED EXECUTIVE OFFICERS


The executive officers of CL&P listed in the Summary Compensation Table in this Item 11 whose compensation is discussed in this CD&A are CL&P's principal executive officers during 2014 (Mr. Olivier and Mr. Schweiger), principal financial officer (Mr. Judge) and the three most highly compensated executive officers other than the principal executive officers and principal financial officer serving on December 31, 2014 (Messrs. May, McHale, and Butler) (collectively, referred to as the "Named Executive Officers" or "NEOs").  Each NEO of CL&P also serves as an executive officer of NU and one or more other subsidiaries of NU.  Compensation for the NEOs discussed in this CD&A was paid for all services provided by such individuals in all capacities to NU and its subsidiaries.  For 2014, CL&P's NEOs are:


·

Thomas J. May, Chairman of the Board, President and Chief Executive Officer of NU; Chairman of the Board of CL&P

·

James J. Judge, Executive Vice President and Chief Financial Officer of NU and CL&P

·

Leon J. Olivier, Executive Vice President – Enterprise Energy Strategy and Business Development of NU

·

David R. McHale, Executive Vice  President and Chief Administrative Officer of NU and CL&P

·

Werner J. Schweiger, Executive Vice President and Chief Operating Officer of NU; Chief Executive Officer of CL&P

·

Gregory B. Butler, Senior Vice President and General Counsel of NU and CL&P


OVERVIEW OF COMPENSATION PROGRAM


The Role of the Compensation Committee.  The NU Board of Trustees has delegated to the Committee overall responsibility for establishing the compensation program for those senior executive officers referred to in this Compensation Discussion and Analysis as "executives" and who under the SEC's regulations are deemed to be "officers."  In this role, the Committee sets compensation policy and compensation levels, reviews and approves performance goals and evaluates executive performance.  Although this discussion and analysis refers principally to compensation for the Named Executive Officers, the same compensation principles and practices apply to all executives.  The compensation of NU's Chief Executive Officer is subject to the further review and approval of the independent Trustees.


Elements of Compensation.  Total direct compensation consists of three elements: base salary, annual cash incentive awards and long-term equity-based incentive awards.  Indirect compensation is provided through certain retirement, perquisite, severance, and health and welfare benefit programs.  


NU's Compensation Objectives.  The objectives of NU's compensation program are to attract and retain superior executive talent, motivate executives to achieve annual and long-term performance goals set each year, and provide total compensation opportunities that are competitive with market practices.  With respect to incentive compensation, the Committee believes it is important to balance short-term goals, such as producing earnings, with longer-term goals, such as creating long-term value and maintaining a strong balance sheet.  The Committee also places great emphasis on system reliability and superior customer service.  NU's compensation program utilizes performance-based incentive compensation to reward individual and corporate performance and to align the interests of executives with the company's customers and shareholders.  The Committee continually increases expectations to motivate executives and employees to achieve continuous improvement in carrying out NU's responsibilities to its customers to deliver energy reliably, safely, with respect for the environment and employees, and at a reasonable cost, while providing an above-average total shareholder return to NU's shareholders.


Setting Compensation Levels.  In order to ensure that the company achieves its goal of providing market-based compensation levels to attract and retain top quality management, the Committee provides executives with target compensation opportunities over time approximately equal to median compensation levels for executive officers of companies comparable to NU.  To achieve that goal, the Committee and its independent compensation consultant work together to determine the market values of executive direct compensation elements (base salaries, annual incentives and long-term incentives), as well as total compensation, by using competitive market compensation data.  The Committee reviews compensation data obtained from utility and general industry surveys and a specific group of peer utility companies.  


Role of the Compensation Consultant.  The Committee has retained Pay Governance as its independent compensation consultant.  Pay Governance reports directly to the Committee and does not provide any other services to NU.  With the consent of the Committee, Pay Governance works cooperatively with NU's management to develop analyses and proposals for presentation to the Committee.  The Committee generally relies on Pay Governance for peer group market data and information as to market practices and trends to assess the competitiveness of the compensation NU pays to executives and to review the Committee's proposed compensation decisions.  




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In February 2015, the Committee assessed the independence of Pay Governance pursuant to SEC and NYSE rules and concluded that it is independent and that no conflict of interest exists that would prevent Pay Governance from independently advising the Committee.  In making this assessment, the Committee considered the independence factors enumerated in Rule 10C-1(b) under the Securities Exchange Act of 1934, including the written representations of Pay Governance that Pay Governance does not provide any other services to NU, the level of fees received from NU as a percentage of Pay Governance's total revenues, the policies and procedures employed by Pay Governance to prevent conflicts of interest, and whether the individual advisers from Pay Governance with whom the Committee consulted own any NU common shares or have any business or personal relationships with members of the Committee or NU's executives.


Role of Management.  The role of NU's management, and specifically the roles of NU's Chief Executive Officer and its Senior Vice President of Human Resources, is to provide current compensation information to the compensation consultant and analyses and recommendations on executive compensation to the Committee based on the market value of the position, individual performance, experience and internal pay equity.  NU's Chief Executive Officer also provides recommendations on the compensation for the other Named Executive Officers.  None of the executives makes recommendations that affect his or her individual compensation.


MARKET ANALYSIS


The Committee strives to provide executives with target compensation opportunities using a range that is approximately equal to the median compensation levels for executive officers of companies comparable to the Company.  Set forth below is a description of the sources of the compensation data used by the Committee when reviewing 2014 compensation:


·

Utility and general industry survey data.  The Committee reviews compensation information obtained from surveys of diverse groups of utility and general industry companies that represent NU's market for executive officer talent.  Utility industry data are based on a defined peer set, as discussed below.  General industry data are size-adjusted to ensure a close correlation between the market data and NU's scope of operations.  The Committee used this information, which it obtained from Pay Governance, to determine base salaries and incentive opportunities.


·

Peer group data.  In support of executive pay decisions during 2014, the Committee consulted with Pay Governance, which provided the Committee with a competitive assessment analysis of NU's executive compensation levels, as compared to the 20 peer group companies listed in the table below.  


Alliant Energy Corporation

Edison International

Public Service Enterprise Group, Inc.

Ameren Corporation

Entergy Corporation

SCANA Corporation

CenterPoint Energy, Inc.

Integrys Energy Group, Inc.

 Sempra Energy

Consolidated Edison Inc.

OGE Energy Corp.

TECO Energy, Inc.

CMS Energy Corp.

Pepco Holdings, Inc.

Wisconsin Energy Corp.

Dominion Resources, Inc.

PG&E Corp.

Xcel Energy Inc.

DTE Energy Company

PPL Corporation

 


The Committee periodically adjusts the target percentages of annual and long-term incentives based on the survey data after discussion with the compensation consultant to ensure that they are approximately equal to competitive median levels.   


The Committee also determines perquisites to the extent they serve business purposes and sets supplemental benefits at levels that provide market-based compensation opportunities to the executives.  The Committee periodically reviews the general market for supplemental benefits and perquisites using utility and general industry survey data, including data obtained from companies in the peer group.


Mix of Compensation Elements.  NU targets the mix of compensation for its Chief Executive Officer and the other Named Executive Officers so that the percentages of each compensation element are approximately equal to the competitive median market mix.  The mix is heavily weighted toward incentive compensation, and incentive compensation is heavily weighted toward long-term compensation.  Since the most senior positions have the greatest responsibility for implementing long-term business plans and strategies, a greater proportion of total compensation is based on performance with a long-term focus.  


The Committee determines the compensation for each executive based on the relative authority, duties and responsibilities of the executive.  NU's Chief Executive Officer's responsibilities for the strategic direction and daily operations and management of NU are greater than the duties and responsibilities of the other executives.  As a result, the compensation of NU's Chief Executive Officer is higher than the compensation of the other executives.  Assisted by the compensation consultant, the Committee regularly reviews market compensation data for executive officer positions similar to those held by the executives, including NU's Chief Executive Officer, and this market data continues to indicate that chief executive officers are paid significantly more than other executive officers.  




148


The following tables set forth the contribution to 2014 Total Direct Compensation (TDC) of each element of compensation, at target, reflected as a percentage of TDC, for the Named Executive Officers.  The amounts shown in this table are at target and therefore do not match the amounts appearing in the Summary Compensation Table.


 

Percentage of TDC at Target

 

 

 

 

Long-Term Incentives

 

Named Executive Officer (NEO)

Base Salary

Annual Incentive(1)

Performance Shares(1)

RSUs(2)

TDC

Thomas J. May

16%

18%

33%

33%

100%

James J. Judge

29%

19%

26%

26%

100%

Leon J. Olivier

29%

19%

26%

26%

100%

David R. McHale

29%

19%

26%

26%

100%

Werner J. Schweiger

30%

20%

25%

25%

100%

Gregory B. Butler

29%

19%

26%

26%

100%

NEO average, excluding CEO

29%

19%

26%

26%

100%


(1)

The annual incentive compensation element and performance shares under the long-term incentive compensation element are performance-based.

(2)

Restricted Share Units (RSUs) vest over three years contingent upon continued employment.


Risk Analysis of Executive Compensation Program.  The overall compensation program includes a mix of compensation elements ranging from a fixed base salary that is risk-neutral to annual and long-term incentive compensation programs intended to motivate officers and eligible employees to achieve individual and corporate performance goals that reflect an appropriate level of risk.  The fundamental objective of the compensation program is to foster the continued growth and success of the business.  The design and implementation of the overall compensation program provides the Committee with opportunities throughout the year to assess risks within the compensation program that may have a material effect on NU and its shareholders.


In 2014, the Committee assessed the risks associated with the executive compensation program by reviewing the various elements of incentive compensation.  The annual incentive program was designed to ensure an appropriate balance between individual and corporate goals, which were deemed appropriate and supportive of NU's annual business plan.  Similarly, the long-term incentive program was designed to ensure that the performance metrics were properly weighted and supportive of NU's strategic plan.  The Committee reviewed the overall compensation program in the context of the annual operating and strategic plans, which were both previously subject to Enterprise Risk Management review.  Both the annual and long-term incentive programs were designed to ensure that mechanisms exist to mitigate risk.  These mechanisms include realistic goal setting and discretion with respect to actual payments, the mix of financial, operational, customer service and safety goals, executive share ownership guidelines linking executive interests to those of shareholders, provisions for the clawback of incentive compensation, prohibitions on hedging and pledging of NU common shares, and the provision of limited perquisites.  These mechanisms are intended to ensure that there is not undue incentive to achieve any one goal without considering the impact of achieving such goal on other aspects of NU's business.

Results of NU's 2014 Say-on-Pay Vote.  NU provides its shareholders with the required opportunity to cast an annual advisory vote on executive compensation (a "Say-on-Pay" proposal).  At NU's Annual Meeting of Shareholders held on May 1, 2014, 91 percent of the votes cast on the Say-on-Pay proposal were voted to approve the 2013 compensation of the Named Executive Officers, as described in NU's 2014 proxy statement.  The Committee has and will continue to consider the outcome of NU's Say-on-Pay votes when making future compensation decisions for the Named Executive Officers.


ELEMENTS OF 2014 COMPENSATION


Base Salary


Base salary is designed to attract and retain key executives by providing an element of total compensation at levels competitive with those of other executives employed by companies of similar size and complexity in the utility and general industries.  In establishing base salary, the Committee relies on compensation data obtained from independent third-party surveys of companies and from an industry peer group to ensure that the compensation opportunities NU offers are capable of attracting and retaining executives with the experience and talent required to achieve its strategic objectives.  


When setting or adjusting base salaries, the Committee considers annual executive performance appraisals; market pay movement across industries (determined through market analysis); targeted market pay positioning for each executive; individual experience and years of service; strategic importance of a position; and internal equity.


Individuals who are performing well in strategic positions are likely to have their base salaries increased more significantly than other individuals.  From time-to-time, economic conditions and corporate performance have caused base salary increases to be postponed.  However, the Committee prefers to reflect sub-par corporate performance through the variable pay components.


In February 2014, the Committee adjusted the base salaries of the Named Executive Officers by 3 percent.  The Committee and independent Trustees also adjusted Mr. May's base salary by 3 percent.




149


Incentive Compensation


Annual incentive and the long-term incentive compensation are provided under the Company's Incentive Plan, which was approved by NU's shareholders at the 2007 Annual Meeting of Shareholders and, with respect to the material terms of performance goals, was re-approved by the shareholders at the 2012 Annual Meeting of Shareholders. The annual incentive program provides cash compensation intended to reward performance under NU's annual operating plan.  The long-term stock-based incentive program is designed to reward demonstrated performance and leadership, motivate future performance, align the interests of the executives with those of NU's shareholders, and retain the executives during the term of grants.  The annual and long-term programs are designed to strike a balance between short- and long-term objectives so that the programs work in tandem.  


2014 ANNUAL INCENTIVE PROGRAM


In February 2014, the Committee established the terms of the 2014 Annual Incentive Program.  As part of the overall program, and after consulting with Pay Governance, the Committee set target award levels for each of the Named Executive Officers that ranged from 60 percent to 110 percent of target.  Target award levels under the Annual Incentive Program are expressed as a percentage of base salary.  


At the February 2014 meeting, the Committee determined that for 2014 it would base 70 percent of the annual incentive performance goals on NU's overall financial performance and 30 percent of the annual performance goals on NU's overall operational performance.  The Committee also determined the specific goals to assess performance and that the individual goals would be assessed using ratings ranging from 0 percent to 200 percent.  The Committee assigned weightings to each of these specific goals: for the financial component, the earnings per share goal was weighted at 60 percent, the reduction in operating expenses goal was weighted at 20 percent, and the remaining 20 percent weighting was based on the combined dividend growth and credit rating goals.  For the operational component, the Committee determined that the combined service reliability and responsiveness goals would be weighted at 60 percent, the combined customer service and merger integration goals would be weighted at 25 percent, and the combined safety ratings, gas service response and call center performance goals would be weighted at 15 percent.  


With respect to 2014 performance, management provided an initial review of the Company's performance for the year at the December 2014 meeting of the Committee, followed in February 2015 by a full assessment of the performance goals, the additional accomplishments noted below under the caption "Additional Factors" and the overall performance of NU.  The Committee was also provided updates during the year on corporate performance.  At the February 2015 meeting, the Committee determined, based on its assessment of the financial and operational performance goals, to set the level of achievement of combined financial and operational performance goals results at 161 percent of target, reflecting the overall excellent performance of NU and the executive team.  In arriving at this determination, the Committee determined that the financial performance goals result was 163 percent of target and the operational performance goals result was 158 percent of target.  The individual financial and operational performance goals results are as set forth below.  NU's Chief Executive Officer recommended to the Committee payout levels for the executives (other than himself) based on his assessment of each executive's individual performance towards achievement of the performance goals and the additional accomplishments of NU, together with each executive's contributions to the overall performance of NU.  The awards determined by the Committee were also based on the same three-component criteria.


Financial Performance Goals Assessment


NU achieved its goal of recurring earnings per share of $2.65 in 2014, exclusive of merger related costs, a 4.7 percent increase over 2013 and compared to an expected industry increase of approximately 4.5 percent.  The Committee determined this goal to be a significant accomplishment, particularly in light of an unfavorable ruling from the Federal Energy Regulatory Commission that lowered NU's return on equity and resulted in a $0.07 per share charge to earnings, and the fact that NU had previously grown earnings 11 percent in 2013.  The Committee determined this goal to have attained a 150 percent performance result.

 

NU continued to achieve operations and maintenance expense reductions through successful integration initiatives, resulting in a 6.8 percent reduction in operating expenses in 2014.  This exceeded the goal of more than a 3 percent reduction and compared with an expected average industry increase of 2 percent.  The Committee determined this goal to have attained a 200 percent performance result.


NU increased its dividend to $1.57 per share, a 6.8 percent increase from the prior year and significantly above the industry average dividend growth of 3.7 percent.  The Committee determined this goal to have attained a 175 percent performance result in light of both the 2014 percentage increase and the previous dividend growth realized in 2013.


NU's credit rating at Standard & Poor's is currently "A-," among the highest in the utility industry, providing the foundation for favorable financing opportunities during the year and in the future.  The industry average credit rating at Standard & Poor's is "BBB+."  In addition, during the year Standard & Poor's raised the outlook on NU's credit rating to "positive" from "stable."  The Committee determined this goal to have attained a 150 percent performance result.


Operational Performance Goals Assessment


NU's total electric system operating performance was the best on record.  Average months between interruptions in service equaled 15.4 months, 18 percent better than the goal of 13.1 months and exceeding the industry average of 13.2 months. System average restoration duration equaled 82 minutes, 15 percent better than the established goal of 96.1 minutes and significantly below the industry average of 123.2 minutes.  Both of these results indicate top quartile performance against industry peers.  The Committee determined these goals to have each attained a 175 percent performance result.




150


NU completed several important integration initiatives across the company, including the implementation of an out-sourced IT business model, a new financial and reporting and budgeting general ledger system, and a facilities consolidation program that streamlined operating effectiveness.  The Committee determined this goal to have attained a 150 percent performance result.


NU continued to improve the customer experience through substantial progress on several customer initiatives, including its "Above and Beyond for our Customers-Driving To Top Tier" initiative of improving customer service; the implementation of "Blue Sky" outage information improvements; its "Voice of the Customer" program; and the creation of the exciting new brand, Eversource Energy, which captures the company's dedication to great customer service.  The Committee determined this goal to have attained a 150 percent performance result.


On-time response to gas customer emergency calls was 99.2 percent, which exceeded the goal of 99.1 percent.  The Committee determined this goal to have attained a 100 percent performance result.


86.2 percent of customer calls were answered within 30 seconds, which exceeded the goal of 85.6 percent.  The Committee determined this goal to have attained a 100 percent performance result.


NU achieved a safety performance goal of 1.44 Days Away & Restricted Time ("DART") per 1,000 employees, exceeding the goal of 1.5.  The Committee determined this goal to have attained a 100 percent performance result.


Additional Factors


The following results were also considered by the Committee in making an assessment of overall financial and operational performance, but were not given specific weightings or assigned a specific performance assessment score:


NU announced a partnership with Spectra Energy Corp to bring much needed natural gas capacity into New England.


NU obtained several constructive regulatory approvals and decisions in Connecticut, Massachusetts and New Hampshire.


NU successfully completed its $1.7 billion capital plan to improve reliability and customer service and also responded very well to several major storms across its service territory.


NU implemented important employee engagement and corporate culture initiatives and streamlined and simplified many processes across the company, in concert with its "One Company" model.


NU's cumulative total shareholder returns of 30.5 percent, 64.3 percent, 145.8 percent, and 297.7 percent over the past one-, three-, five-, and 10-year periods outperformed the utility industry over those same periods.


Individual Performance Factors Considered by the Committee


The goal of the Committee for 2014 was to continue to provide incentives for executives to work together as a highly effective, integrated team to achieve or exceed the financial, operational, customer and process integration goals and objectives.  While emphasizing the importance of executives working as a team, the annual incentive award payments were also based on the Committee's assessment of each executive's individual performance in supporting the performance goals, additional achievements and overall company performance.  The Committee assessed the performance of NU's Chief Executive Officer and, based on the recommendations of the Chief Executive Officer, the Named Executive Officers, to determine the individual incentive awards as disclosed in the Summary Compensation Table.  Based on the Committee's review, which included its assessment of the performance goals, the significant other accomplishments of NU and the Named Executive Officers, and the overall performance of NU and each of Named Executive Officers, considered in its totality by the Committee to have been excellent, the Committee approved annual incentive program payouts for the Named Executive Officers at levels that ranged from 154 percent to 171 percent of target.  These awards reflected the individual and team contributions of Mr. May, Mr. Judge, Mr. Olivier, Mr. McHale, Mr. Schweiger and Mr. Butler in achieving the goals and the additional accomplishments and the overall performance of the company.


In arriving at Mr. May's annual incentive payment of $2,250,000, which was 170 percent of target, and which reflects his and NU's excellent performance, the Committee and the Board considered the totality of NU's success in accomplishing the financial, operational, customer and merger effectiveness goals, the additional accomplishments of the company, and Mr. May's strategic leadership of NU.




151


2014 Annual Incentive Program Performance Assessments


Financial Performance Goals








Financial

Performance


Category


2014 Goal


Company Performance

Indicative

Assessment

Earnings Per Share


$2.65 per share

Achieved  - $2.65 per share, a 4.7% increase over 2013, outperforming expected industry peer growth of approximately 4.5%


150%

Reduce Operating Expenses

Reduce operating expenses to $1,424 million, or a more than 3% reduction

 Exceeded  - 2014 Operating Expenses were $1,392 million, or 6.8% below 2013 results


200%

Dividend Growth

Increase NU's dividend $.10 to $1.57 per share

Achieved  - Increased to $1.57 per share, a  $.10 increase and 6.8% growth, significantly exceeding the industry average growth of 3.7%


175%

Credit Rating

Maintain NU's top tier Standard & Poor's (S&P) A- credit rating

Achieved – S&P rating A- (with "new" Positive Outlook), among the highest in the utility industry


150%

Weightings = EPS - 60%; Reduce Operating Expenses - 20%; dividend/credit - 20%              


Operational Performance Goals












Operational Performance


Category


2014 Goal


Company Performance

Indicative Assessment

Reliability – Avg. Months Between Interruptions (MBI)


Achieve MBI of 13.1

Exceeded - MBI 15.4;

18% better than goal and in top quartile of peers


175%

Average Restoration Duration (SAIDI)

Achieve SAIDI of 96.1

minutes

Exceeded - SAIDI 82 minutes;

15% better than goal and in top quartile of peers


175%

Improve the Customer Experience

Implement customer service  initiatives

Achieved - Major initiatives (customer service, outage information and branding) achieved



150%

Merger Integration

Execute on key merger integration initiatives

Achieved - Significant IT, general ledger and facilities initiatives achieved, lowering costs and streamlining operations


150%

Safety Rate

1.5 DART

Achieved - 1.44 DART

100%

Gas Service Response

99.1%

Achieved - 99.2%

100%

Calls Answered

85.6%

Achieved - 86.2%

100%

Weightings = Reliability and Restoration – 60%; Important Corporate Initiatives – 25%;

Safety/Gas Service Response/Calls Answered Rate – combined 15%


Performance Goals Assessment


Financial Performance (weighted 70%)

163%

Operational Performance (weighted 30%)

158%

Overall Performance

161%


LONG-TERM INCENTIVE PROGRAM


General


NU's long-term incentive program is intended to focus on the company's longer-term strategic goals and to help retain the executives.  A new three-year program commences every year.  For the 2014 – 2016 Long-Term Incentive Program, at target, each grant consisted of 50 percent Restricted Share Units (RSUs) and 50 percent Performance Shares.  RSUs are designed to provide executives with an incentive to increase the value of Company common shares in alignment with shareholder interests, while also serving as a retention component for executive talent.  Performance Shares are designed to reward achievement as measured against pre-established performance measures.  NU believes these compensation elements create a focus on continued company and NU share price growth to further align the interests of the executives with the interests of NU's shareholders.




152


Restricted Share Units (RSUs)


General


Each RSU granted under the long-term incentive program entitles the holder to receive one NU common share at the time of vesting.  All RSUs granted under the long-term incentive program provide for vesting in equal annual installments over three years.  RSU holders are eligible to receive reinvested dividend units on outstanding RSUs held by them to the same extent that dividends are declared and paid on NU common shares.  Reinvested dividend units are accounted for as additional RSUs that accrue and are distributed with the common shares issued upon vesting of the underlying RSUs.  Common shares, including any additional common shares in respect of reinvested dividend units, are not issued for any RSUs that do not vest.


The Committee determined RSU grants for each officer participating in the long-term incentive program.  RSU grants are based on a percentage of base salary and measured in dollars.  In 2014, the percentage used for each officer was based on the executive officer's position in the company and ranged from 75 percent to 200 percent of base salary.  The Committee reserves the right to increase or decrease the RSU grant from target for each officer under special circumstances.  Based on input from NU's Chief Executive Officer, the Committee determined the final RSU grants for each of the other executive officers, including the other Named Executive Officers.


All RSUs are granted on the date of the Committee meeting at which they are approved. RSU grants are subsequently converted from dollars into common share equivalents by dividing the value of each grant by the average closing price for NU common shares over the ten trading days prior to the date of the grant.


RSU Grants under the 2014 2016 Program


Under the 2014 – 2016 Program, the target RSU grant totaled approximately $7,741,835 for the 49 NU officers participating in the program.  Dividing the final total RSU grant by $43.13, the average closing price of NU common shares over the ten trading days prior to the date of grant, resulted in an aggregate of 179,500 RSUs.  The following RSU grants at 100 percent of target were approved, reflected in RSUs: Mr. May: 55,900; Mr. Judge: 12,400; Mr. Olivier: 13,000; Mr. McHale: 12,400; Mr. Schweiger: 8,700 and Mr. Butler: 8,600.


RSU Grants under the 2013 2015 Program


Under the 2013 – 2015 Program, the target RSU grant totaled approximately $7,057,248 for the 44 NU officers participating in the program.  Dividing the final total RSU grant by $39.36, the average closing price of NU common shares over the ten trading days prior to the date of grant, resulted in an aggregate of 179,300 RSUs.  The following RSU grants at 100 percent of target were approved, reflected in RSUs: Mr. May: 52,000; Mr. Judge: 13,100; Mr. Olivier: 13,800; Mr. McHale: 13,100; Mr. Schweiger: 9,300 and Mr. Butler: 9,100.


Performance Share Grants


General


Performance Shares are designed to reward future financial performance, measured by long-term earnings growth and above-average total shareholder returns, therefore aligning compensation with performance.


Performance Shares under the 2014 – 2016 Program


The Committee determined to use: (i) average diluted NU earnings per share growth adjusted for certain non-recurring items ("EPSG"); and (ii) relative NU total shareholder return ("TSR") measured against the performance of companies that comprise the EEI Index.  As in 2013, the Committee selected EPSG and TSR as performance measures because the Committee believes that they are generally recognized as the best indicators of overall corporate performance.   Further, the Committee considers it a best practice to use a combination of relative and absolute metrics, with EPS growth serving as a key input to shareholder value and TSR serving as the output.


The number of Performance Shares awarded at the end of the three-year period ranges from 0 percent to 200 percent of target, depending on EPSG and relative TSR performance as set forth in the performance matrix below.  For the 2014 – 2016 Program, EPSG ranges from 0 percent to 9 percent, while TSR ranges from below the 10th percentile to approximately above the 90th percentile.  The Committee determined that payout at 100 percent of target should be challenging but achievable.  As a result, vesting at 100 percent of target occurs at various combinations of EPSG and TSR performance.  In addition, the value of any performance shares that actually vest may increase or decrease over the vesting period based on NU's share price performance.  




153


The performance matrix set forth below describes how the Performance Share payout is determined under the 2014 – 2016 Program.  Actual three-year average EPSG is cross-referenced with the actual three-year TSR percentile to determine actual performance share payout as a percentage of target:


2014 – 2016 Long-Term Incentive Program Performance Share Payout

Three-Year
Average
EPS Growth

Three-Year Relative Total Shareholder Return Percentiles

Below

10th

20th

30th

40th

50th

60th

70th

80th

90th

Above 90th

9%

110%

120%

130%

140%

150%

160%

170%

180%

190%

200%

8%

100%

110%

120%

130%

140%

150%

160%

170%

180%

190%

7%

90%

100%

110%

120%

130%

140%

150%

160%

170%

180%

6%

80%

90%

100%

110%

120%

130%

140%

150%

160%

170%

5%

70%

80%

90%

100%

110%

120%

130%

140%

150%

160%

4%

60%

70%

80%

90%

100%

110%

120%

130%

140%

150%

3%

40%

50%

70%

80%

90%

100%

110%

120%

130%

140%

2%

20%

40%

60%

70%

80%

90%

100%

110%

120%

130%

1%

0%

10%

40%

60%

70%

80%

90%

100%

110%

120%

0%

0%

0%

20%

30%

50%

70%

80%

90%

100%

110%

Below 0%

0%

0%

0%

0%

10%

20%

30%

40%

50%

60%


Performance Shares under the 2013 – 2015 Program


The Committee also determined to use: (i) EPSG; and (ii) TSR measured against the performance of companies that comprise the EEI Index.  For the 2013 – 2015 Program, the number of Performance Shares awarded at the end of the three-year period ranges from 0 percent to 200 percent of target, depending on EPSG and relative TSR performance as set forth in the performance matrix.  EPSG ranges from 0 percent to 10 percent, while TSR ranges from below the 10th percentile to approximately above the 90th percentile.  The Committee determined that payout at 100 percent of target should be challenging but achievable.  As a result, vesting at 100 percent of target occurs at various combinations of EPSG and TSR performance.  In addition, the value of any performance shares that actually vest may increase or decrease over the vesting period based on the Company's share price performance.  


The performance matrix set forth below describes how the Performance Share payout is determined under the 2013 – 2015 Program.  Actual three-year average EPSG is cross-referenced with the actual three-year TSR percentile to determine actual performance share payout as a percentage of target:


2013 – 2015 Long-Term Incentive Program Performance Share Payout

Three-Year
Average
EPS Growth

Three-Year Relative Total Shareholder Return Percentiles

Below

10th

10th

20th

30th

40th

50th

60th

70th

80th

90th

Above 90th

10%

100%

110%

120%

130%

140%

150%

160%

170%

180%

190%

200%

9%

90%

100%

110%

120%

130%

140%

150%

160%

170%

180%

190%

8%

80%

90%

100%

110%

120%

130%

140%

150%

160%

170%

180%

7%

70%

80%

90%

100%

110%

120%

130%

140%

150%

160%

170%

6%

60%

70%

80%

90%

100%

110%

120%

130%

140%

150%

160%

5%

50%

60%

70%

80%

90%

100%

110%

120%

130%

140%

150%

4%

40%

50%

60%

70%

80%

90%

100%

110%

120%

130%

140%

3%

30%

40%

50%

60%

70%

80%

90%

100%

110%

120%

130%

2%

20%

30%

40%

50%

60%

70%

80%

90%

100%

110%

120%

1%

0%

20%

30%

40%

50%

60%

70%

80%

90%

100%

110%

0%

0%

0%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Below 0%

0%

0%

0%

0%

0%

10%

20%

30%

40%

50%

60%


2012 – 2014 (Pre-Merger) Long-Term Incentive Program


The 2012-2014 Program was approved prior to the 2012 merger with NSTAR.  Grants under the Program consisted of 50 percent RSUs and 50 percent Performance Shares.  The RSU grants under this three-year program vest in equal annual installments and are otherwise subject to the provisions set forth in the section above titled "Restricted Share Units (RSUs)."  Upon the closing of the merger in 2012, the Performance Share grants under this program converted to RSUs assuming a target level of performance, and the newly converted RSUs were made subject to the vesting schedule for the original RSU grants under each program.  Under the 2012 – 2014 Program, half of the newly converted RSUs vested in 2013 and the remaining half vested in 2014.  


CLAWBACKS


If NU's earnings were to be restated as a result of noncompliance with accounting rules caused by fraud or misconduct, NU would require its Chief Executive Officer and Chief Financial Officer to provide reimbursements for certain incentive compensation received by each of them.  To the extent that reimbursement were not required under SEC rules or NYSE listing standards, NU's Incentive Plan would require any employee whose



154


misconduct or fraud caused such restatement, as determined by NU's Board of Trustees, to reimburse NU for any incentive compensation received by him or her.  


In addition, once final rules are adopted by the SEC regarding any additional clawback requirements under the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd Frank), NU will review its clawback policy and compensation plans and, if necessary, amend them to comply with the new mandates.  


NO HEDGING AND NO PLEDGING POLICY


NU has adopted a policy prohibiting the purchase of financial instruments or otherwise entering into transactions designed to have the effect of hedging or offsetting any decrease in the value of NU common shares by its Trustees and employees, including executive officers.  This policy also prohibits all pledging, derivative transactions of short sales involving NU common shares or the holding of any NU common shares in a margin account.


SHARE OWNERSHIP GUIDELINES/HOLDING PERIODS


The Committee has approved share ownership guidelines to further emphasize the importance of share ownership by officers.  As indicated in the table below, the guidelines call for NU's Chief Executive Officer to own NU common shares equal to six times base salary, executive vice presidents and senior vice presidents to own a number of common shares equal to three times base salary and all other officers to own a number of common shares equal to one to two times base salary.


Executive Officer

Base Salary Multiple

Chief Executive Officer

6

Executive Vice Presidents /
Senior Vice Presidents

3

Operating Company Presidents

2

Vice Presidents

1-1.5


NU requires that its officers attain these ownership levels within five years.  All officers, including the Named Executive Officers, have satisfied the share ownership guidelines or are expected to satisfy them within the applicable timeframe.  Common shares, whether held of record, in street name, or in individual 401(k) accounts, and RSUs satisfy the guidelines.  Unexercised stock options and unvested performance shares do not count toward the ownership guidelines.  In addition to the share ownership guidelines requirements noted above, all officers must hold all the net shares awarded under NU's stock compensation plan until the share ownership guidelines requirements have been met.  We will also review this policy when final rules under Dodd-Frank are adopted and will amend our policy and disclosure as appropriate to comply with the rules.


OTHER


Retirement Benefits


NU provides a qualified defined benefit pension program for certain officers, which is a final average pay program subject to tax code limits.  Because of such limits, NU also maintains a supplemental non-qualified pension program. Benefits are based on base salary and certain incentive payments, which is consistent with the goal of providing a retirement benefit that replaces a percentage of pre-retirement income.  The supplemental program makes up for benefits barred by tax code limits, and generally provides (together with the qualified pension program) benefits equal to approximately 60 percent of pre-retirement compensation (subject to certain reductions) for Messrs. May, Judge, Schweiger and Butler, and approximately 50 percent of such compensation for Mr. McHale.  The supplemental program has been discontinued for newly-elected officers.


For certain participants, the benefits payable under the Supplement Non-Qualified Pension Program (Program) differ from those described above.  Under the Key Executive Benefit Plan, Mr. May is entitled to an alternative retirement benefit equal to 33 percent of final base salary annually for 15 years in lieu of the benefits provided under the Program.  Benefits that would be available under the Key Executive Benefit Plan are less than those available under the Program and therefore have not been included in the present value of accumulated benefit shown below.  Upon retirement, Mr. May is entitled to receive the greater of the benefit payable under the Program or the Key Executive Benefit Plan.  Mr. Olivier's employment agreement provides retirement benefits similar to those of a previous employer instead of the supplemental program benefits described above.  Under this agreement, he will receive a pension based on a prescribed formula if he meets certain eligibility requirements.  The Program benefit payable to Mr. Schweiger is fully vested and is further reduced by benefits he is entitled to receive under previous employers' retirement plans.


Also see the narrative accompanying the "Pension Benefits" table and accompanying notes for more detail on the above program.


401(k) Benefits


NU offers a qualified 401(k) program for all employees, including executives, subject to tax code limits.  After applying these limits, the program provides a maximum match of up to $10,400 for Messrs. May, Judge and Schweiger, which is equal to 50 percent of the first 8 percent of eligible base salary and annual cash incentive.  For Messrs. Olivier, McHale and Butler, NU provides a maximum match of up to $7,800, which is equal to 3 percent of eligible base salary and annual cash incentive.



155



Deferred Compensation


NU offers a non-qualified deferred compensation program for executives.  In 2014, the program allowed deferral of up to 100% of base salary, annual incentives and long-term incentive awards.  The program allows participants to select investment measures for deferrals based on an array of deemed investment options (including certain mutual funds and publicly traded securities).  


See the Non-Qualified Deferred Compensation Table and accompanying notes for additional details on the above program.


Perquisites


NU provides executives with limited financial planning, health services, vehicle leasing and access to tickets to sporting events, perquisites that NU believes are consistent with peer companies.  The current level of perquisites does not factor into decisions on total compensation.


CONTRACTUAL AGREEMENTS


NU maintains contractual agreements with all of the Named Executive Officers that provide for potential compensation in the event of certain terminations following a Change of Control.  NU believes these agreements are necessary to attract and retain high quality executives and to ensure executive focus on NU business during the period leading up to a potential Change of Control.  The agreements are "double-trigger" agreements that provide executives with compensation in the event of a Change of Control, while still providing an incentive to remain employed with NU for the transition period that follows.  


Under the agreements, certain compensation is generally payable if, during the applicable change of control period, the executive is involuntarily terminated (other than for cause) or voluntarily terminates employment for "good reason."  These agreements are described more fully below under "Potential Payments upon Termination or Change of Control."   

TAX AND ACCOUNTING CONSIDERATIONS


NU's incentive plan was approved by shareholders and permits annual incentive and performance share awards intended to qualify as performance-based compensation under Section 162(m) of the Internal Revenue Code.  However, NU believes that the availability of a tax deduction for forms of compensation is secondary to the goal of providing market-based compensation to attract and retain highly qualified executives.  In addition, the compensation program plans were amended in 2008 to comply with Section 409A of the Internal Revenue Code.  


NU has adopted the provisions of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 718, Compensation-Stock Compensation.  In general, NU and the Committee do not take accounting considerations into account in structuring compensation arrangements.


EQUITY GRANT PRACTICES


Equity awards noted in the compensation tables are made at the February meeting of the Committee (subject to the further approval of the independent members of NU's Board of Trustees of the Chief Executive Officer's award) when the Committee also determines base salary, annual and long-term incentive compensation targets and annual incentive awards.  The date of this meeting is chosen several months in advance, and therefore awards are not coordinated with the release of material non-public information.




156


SUMMARY COMPENSATION TABLE


The table below summarizes the total compensation paid or earned by CL&P's principal executive officers in 2014 (Mr. Olivier and Mr. Schweiger), principal financial officer (Mr. Judge) and the three most highly compensated executive officers other than the principal executive officers and principal financial officer serving on December 31, 2014 (Messrs. May, McHale, and Butler), determined in accordance with the applicable SEC disclosure rules (collectively, the Named Executive Officers).  As explained in the footnotes below, the amounts reflect the economic benefit to each Named Executive Officer of the compensation item paid or accrued on his behalf for the fiscal year ended December 31, 2014.  The compensation shown for each Named Executive Officer was for all services in all capacities to NU and its subsidiaries.  All salaries, annual incentive amounts and long-term incentive amounts shown for each Named Executive Officer were paid for all services rendered to NU and its subsidiaries, including CL&P, in all capacities.


 

 

 

 

 

Change in

 

 

 

 

 

 

 

Pension

 

 

 

 

 

 

 

Value

 

 

 

 

 

 

 

and Non-

 

 

 

 

 

 

 

Qualified

All Other

 

 

 

 

Stock

Non-Equity

Deferred

Compen-

 

Name and

 

Salary

Awards

Incentive Plan

Earnings

sation

Total

Principal Position

Year

($) (4)

($) (5)

($) (6)

($) (7)

($) (8)

($)

Thomas J. May (1)

2014

1,196,325

5,276,401

2,250,000

182,787

75,004

8,980,517

President and Chief

2013

1,161,250

4,263,480

2,125,000

-

111,269

7,660,999

Executive Officer of NU;

2012

1,125,000

3,418,416

2,100,000

1,232,395

91,726

7,967,537

Chairman of CL&P

 

 

 

 

 

 

 

James J. Judge (1)

2014

587,975

1,170,436

660,000

1,587,879

20,346

4,026,636

Executive Vice President

2013

570,750

1,074,069

650,000

111,279

20,886

2,426,984

and Chief Financial

2012

535,667

793,045

640,000

1,097,100

21,085

3,086,897

Officer of NU and CL&P

 

 

 

 

 

 

 

Leon J. Olivier (2)

2014

617,225

1,227,070

680,000

1,376,886

7,877

3,909,058

Executive Vice President

2013

599,242

1,131,462

670,000

109,818

23,668

2,534,190

Energy Enterprise

2012

583,043

889,147

974,236

887,046

17,491

3,350,963

Strategy and Business

 

 

 

 

 

 

 

Development of NU

 

 

 

 

 

 

 

David R. McHale

2014

587,643

1,170,436

660,000

2,136,933

10,348

4,565,360

Executive Vice President

2013

570,147

1,074,069

650,000

-

22,104

2,316,320

and Chief Administrative

2012

553,853

844,685

939,939

1,127,536

16,615

3,482,628

of NU and CL&P

 

 

 

 

 

 

 

Werner J. Schweiger (3)

2014

538,950

821,193

600,000

1,174,893

205,073

3,340,109

Executive Vice President

 

 

 

 

 

 

 

and Chief Operating

 

 

 

 

 

 

 

Officer of NU; CEO of  

 

 

 

 

 

 

 

CL&P

 

 

 

 

 

 

 

Gregory B. Butler

2014

457,736

811,754

515,000

1,274,208

12,800

3,071,498

Senior Vice President

2013

444,423

746,109

505,000

-

12,650

1,708,182

and General Counsel of

2012

431,885

659,226

727,534

764,758

7,500

2,590,903

NU and CL&P

 

 

 

 

 

 

 


(1)

The 2012 compensation reported for Messrs. May and Judge includes compensation paid by NSTAR during the period from January 1, 2012 to April 9, 2012, prior to the closing of the merger, plus compensation paid by NU for the remainder of 2012, following the closing of the merger.  The 2012 compensation paid by NU consisted of the following.  For Mr. May, Salary: $822,414; Non-Equity Incentive Plan Compensation: $2,100,000; Change in Pension Value and Non-Qualified Deferred Compensation Earnings: $1,232,395; All Other Compensation: $87,821; and Total: $4,242,630.  For Mr. Judge, Salary: $401,215; Non-Equity Incentive Plan Compensation: $640,000; Change in Pension Value and Non-Qualified Deferred Compensation Earnings: $1,097,100; All Other Compensation: $7,500; and Total: $2,145,815.


(2)

Mr. Olivier resigned as Chief Executive Officer of CL&P effective August 11, 2014, and as Executive Vice President and Chief Operating Officer of NU effective September 2, 2014.  He was elected Executive Vice President-Energy Enterprise Strategy and Business Development of NU effective September 2, 2014.


(3)

Mr. Schweiger was elected Chief Executive Officer of CL&P effective August 11, 2014.  He did not meet the requirements for inclusion in the Summary Compensation Table and was not a Named Executive Officer in 2012 and 2013.  Mr. Schweiger was elected Executive Vice President and Chief Operating Officer of NU effective September 2, 2014.  


(4)

Includes amounts deferred in 2014 under the deferred compensation program for Mr. Olivier: $123,446; Mr. McHale: $11,753 and Mr. Schweiger: $997,803.  For more information, see the Executive Contributions in the Last Fiscal Year column of the Non-Qualified Deferred Compensation Plans Table.




157


(5)

Reflects the aggregate grant date fair value of restricted share units (RSUs) and performance shares granted in each fiscal year, calculated in accordance with FASB ASC Topic 718.


In 2013 and 2014 for each Named Executive Officer, and in 2012 for Messrs. Olivier, McHale and Butler, RSUs were granted as long-term compensation that vest in equal annual installments over three years.  RSU holders are eligible to receive dividend equivalent units on outstanding RSUs held by them to the same extent that dividends are declared and paid on our common shares. Dividend equivalent units are accounted for as additional common shares that accrue and are distributed simultaneously with the common shares issued upon vesting of the underlying RSUs.  The 2012 amounts shown for Mr. May and Mr. Judge represent the value of Deferred Shares granted by NSTAR.  See footnote (1).


In 2014, each of the Named Executive Officers was granted performance shares as long-term incentive compensation.  These performance shares will vest on December 31, 2016 based on the extent to which the two performance conditions described in the CD&A are achieved.  The grant date values for the performance shares, assuming achievement of the highest level of both performance conditions, are as follows: Mr. May: $4,112,004; Mr. Judge: $912,144; Mr. Olivier: $956,280 Mr. McHale: $912,144; Mr. Schweiger: $639,972; and Mr. Butler: $632,616.


(6)

Includes payments to the Named Executive Officers under the 2014 Annual Incentive Program (Mr. May: $2,250,000; Mr. Judge: $660,000; Mr. Olivier: $680,000; Mr. McHale: $660,000; Mr. Schweiger: $600,000 and Mr. Butler: $515,000).


(7)

Includes the actuarial increase in the present value from December 31, 2013 to December 31, 2014, of the Named Executive Officer's accumulated benefits under all of our defined benefit pension program and agreements determined using interest rate and mortality rate assumptions consistent with those appearing under the caption "Management's Discussion and Analysis and Results of Operations" in this Annual Report on Form 10-K.  The Named Executive Officer may not be fully vested in such amounts.  More information on this topic is set forth with respect to the Pension Benefits table, appearing further below.  There were no above-market earnings on deferrals in 2014, as the terms of the Deferred Compensation Plan provide for market-based investments, including Company Common Shares.  In 2013, the change in pension value for each of Messrs. May, McHale and Butler was a negative amount.


(8)

Includes matching contributions allocated by us to the accounts of Named Executive Officers under the 401k plan as follows: $10,400 for each of Messrs. May, Judge and Schweiger, and $7,800 for each of Messrs. Olivier, McHale and Butler.  Also includes employer matching contributions under the deferred compensation program for eligible Named Executive Officers who made deferral elections in late 2013 for salary earned in 2014 (Mr. McHale: $9,827 and Mr. Olivier: $10,737).  Mr. Butler did not participate in the deferred compensation program in 2014.  For Mr. May, the value shown includes $53,118 attributable to a previously granted $6.155 million present value life insurance benefit; financial planning services valued at $5,860; $3,086 paid by the Company for Company-leased vehicles.  For Mr. Judge, the value shown includes financial planning services valued at $6,100 and $3,846 paid by the Company for Company-leased vehicles.  For Mr. Schweiger, the value shown includes financial planning services valued at $6,028, $802 paid by the Company for Company-leased vehicles and $187,843 paid by the Company for relocation from Massachusetts to Connecticut.  None of the other Named Executive Officers received perquisites valued in the aggregate in excess of $10,000.




158


GRANTS OF PLAN-BASED AWARDS DURING 2014


The Grants of Plan-Based Awards Table provides information on the range of potential payouts under all incentive plan awards during the fiscal year ended December 31, 2014.  The table also discloses the underlying equity awards and the grant date for equity-based awards.  NU has not granted any stock options since 2002.


 

 

 

 

 

 

 

 

All Other

 

 

 

 

 

 

 

 

 

Stock

Grant

 

 

 

 

 

 

 

 

 Awards:

Date Fair

 

 

 

 

 

 

 

 

Number of

Value of

 

 

Estimated Future Payouts Under

Estimated Future Payouts Under

Shares

Stock and

 

 

Non-Equity Incentive Plan Awards

Equity Incentive Plan Awards (1)

of Stock

Option

 

Grant

Threshold

Target

Maximum

Threshold

Target

Maximum

or Units

Awards

Name

Date

($)

($)

($)

($)

(#)

(#)

(#) (2)

($) (3)

Thomas J. May

 

 

 

 

 

 

 

 

 

Annual Incentive (4)

02/04/2014

662,800

1,325,600

2,651,200

—  

—  

—  

—  

—  

Long-Term Incentive (5)

02/04/2014

—  

—  

—  

—  

55,900

111,800

55,900

5,276,401

James J. Judge

 

 

 

 

 

 

 

 

 

Annual Incentive (4)

02/04/2014

192,500

385,000

770,000

—  

—  

—  

—  

—  

Long-Term Incentive (5)

02/04/2014

—  

—  

—  

—  

12,400

24,800

12,400

1,170,436

Leon J. Olivier

 

 

 

 

 

 

 

 

 

Annual Incentive (4)

02/04/2014

202,000

404,000

808,000

—  

—  

—  

—  

—  

Long-Term Incentive (5)

02/04/2014

—  

—  

—  

—  

13,000

26,000

13,000

1,227,070

David R. McHale

 

 

 

 

 

 

 

 

 

Annual Incentive (4)

02/04/2014

192,500

385,000

770,000

—  

—  

—  

—  

—  

Long-Term Incentive (5)

02/04/2014

—  

—  

—  

—  

12,400

24,800

12,400

1,170,436

Werner J. Schweiger

 

 

 

 

 

 

 

 

 

Annual Incentive (4)

02/04/2014

195,000

390,000

780,000

—  

—  

—  

—  

—  

Long-Term Incentive (5)

02/04/2014

—  

—  

—  

—  

8,700

17,400

8,700

821,193

Gregory B. Butler

 

 

 

 

 

 

 

 

 

Annual Incentive (4)

02/04/2014

149,955

299,910

599,820

—  

—  

—  

—  

—  

Long-Term Incentive (5)

02/04/2014

—  

—  

—  

—  

8,600

17,200

8,600

811,754


(1)

Reflects the number of performance shares granted to each of the Named Executive Officers on February 4, 2014 under the 2014 – 2016 Long-Term Incentive Program.  Performance shares were granted subject to a three-year Performance Period that ends on December 31, 2016.  At the end of the Performance Period, common shares will be awarded based on actual performance as a percentage of target, subject to reduction for applicable withholding taxes.  Holders of performance shares are eligible to receive dividend equivalent units on outstanding performance shares held by them to the same extent that dividends are declared and paid on our common shares.  Dividend equivalent units are accounted for as additional common shares that accrue and are distributed simultaneously with NU common shares underlying the performance shares.  The Annual Incentive Plan does not include an equity component.


(2)

Reflects the number of RSUs granted to each of the Named Executive Officers on February 4, 2014 under the 2014 – 2016 Long-Term Incentive Program.  RSUs vest in equal installments on February 4, 2015, 2016 and 2017. NU will distribute common shares with respect to vested RSUs on a one-for-one basis following vesting, after reduction for applicable withholding taxes.  Holders of RSUs are eligible to receive dividend equivalent units on outstanding RSUs held by them to the same extent that dividends are declared and paid on NU common shares.  Dividend equivalent units are accounted for as additional common shares that accrue and are distributed simultaneously with the NU common shares distributed in respect of the underlying RSUs.


(3)

Reflects the grant-date fair value, determined in accordance with FASB ASC Topic 718, of RSUs and performance shares granted to the Named Executive Officers on February 4, 2014 under the 2014 – 2016 Long-Term Incentive Program.  


(4)

Amounts reflect the range of potential payouts, if any, under the 2014 Annual Incentive Program for each Named Executive Officer, as described in the CD&A.  The payment in 2015 for performance in 2014 is set forth in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table.  The threshold payment under the Annual Incentive Program is 50 percent of target.  


(5)

Reflects the range of potential payouts, if any, pursuant to performance share awards under the 2014 – 2016 Long-Term Incentive Program, as described in the CD&A.




159



EQUITY GRANTS OUTSTANDING AT DECEMBER 31, 2014


The following table sets forth option and RSU grants outstanding at the end of our fiscal year ended December 31, 2014 for each of the Named Executive Officers.  All outstanding options were fully vested as of April 10, 2012.


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Option Awards (1)

 

Stock Awards (2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Incentive

 

 

 

 

 

 

 

 

 

 

 

 

Equity Incentive

 

Plan Awards:

 

 

 

 

 

 

 

 

 

 

 

 

Plan Awards:

 

Market or Payout

 

 

Number of

 

 

 

 

 

Number of

 

Market Value

 

Number of

 

Value of

 

 

Securities

 

 

 

 

 

Shares or

 

of Shares or

 

Unearned

 

Unearned

 

 

Underlying

 

 

 

 

 

Units of

 

Units of

 

Shares, Units or

 

Shares, Units or

 

 

Unexercised

 

Option

 

 

 

Stock that

 

Stock that

 

Other Rights

 

Other Rights

 

 

Options

 

Exercise

 

Option

 

have not

 

have not

 

That Have Not

 

That Have Not

 

 

Exercisable

 

Price

 

Expiration

 

Vested

 

Vested

 

Vested

 

Vested

Name

 

(#)

 

($)

 

Date

 

(#) (3)

 

($) (4)

 

(#)

 

($)

Thomas J. May

 

174,496

 

26.9000

 

1/28/2020

 

 

 

 

 

 

 

 

 

130,903

 

7,005,912

 

113,412

 

6,069,810

James J. Judge

 

 

 

 

107,782

 

5,768,468

 

26,832

 

1,436,049

Leon J. Olivier

 

 

 

 

88,063

 

4,713,154

 

28,201

 

1,509,318

David R. McHale

 

 

 

 

104,935

 

5,616,122

 

26,832

 

1,436,049

Werner J. Schweiger

 

47,232

 

28.1200

 

5/3/2017

 

 

 

 

 

 

39,360

 

24.7400

 

1/24/2018

 

 

 

 

 

 

48,544

 

25.9300

 

1/22/2019

 

 

 

 

 

 

36,736

 

26.9000

 

1/28/2020

 

 

 

 

 

 

 

 

 

92,021

 

4,924,953

 

18,942

 

1,013,776

Gregory B. Butler

 

 

 

 

77,732

 

4,160,216

 

18,625

 

996,810


(1)

Options held by Mr. May and Mr. Schweiger were granted by NSTAR before the Merger and assumed by NU upon completion of the Merger.


(2)

Awards and market values of awards appearing in the table and the accompanying notes have been rounded to whole units.


(3)

A total of 154,815 unvested RSUs vested after January 1 and on or before February 25, 2015 (Mr. May: 73,839 and Mr. Judge: 17,304; Mr. Olivier: 18,804; Mr. McHale: 17,878; Mr. Schweiger: 13,810 and Mr. Butler: 13,180). A total of 77,616 unvested RSUs will vest on February 4, 2016 (Mr. May: 37,805; Mr. Judge: 8,944; Mr. Olivier: 9,400; Mr. McHale: 8,944; Mr. Schweiger: 6,314 and Mr. Butler: 6,209).  A total of 38,244 unvested RSUs will vest on February 4, 2017 (Mr. May: 19,259; Mr. Judge: 4,273; Mr. Olivier: 4,479; Mr. McHale: 4,273; Mr. Schweiger: 2,997 and Mr. Butler: 2,963).


In connection with the Merger, in November 2010, NU and NSTAR each established retention pools in an aggregate amount of $10 million to be allocated to key employees, including certain executive officers, to help ensure their continued dedication to each company both before and after completion of the Merger.  Awards were in the form of RSUs and generally vest subject to three years of continuous service following completion of the Merger.  Full payment will also be made if an eligible executive dies, becomes disabled, or is terminated by NU without "cause" before the end of the retention period, in which case the retention payment will be reduced by the amount of any cash severance payable to the executive upon or during the year following termination.  Awards granted to former NSTAR executive officers were assumed by NU upon completion of the Merger.  An additional 330,760 unvested RSUs granted pursuant to the retention pools will vest on April 10, 2015, subject to three years of continuous service following completion of the Merger (Mr. Judge: 77,260; Mr. Olivier: 55,380; Mr. McHale: 73,840; Mr. Schweiger: 68,900 and Mr. Butler: 55,380).  Mr. May did not participate in this program.


(4)

The market value of RSUs is determined by multiplying the number of RSUs by $53.52, the closing price of NU common shares on December 31, 2014, the last trading day of the year.


(5)

Reflects the target payout level for 2014 performance shares.  The payout for 2014 performance shares will be based on actual performance as a percentage of target, subject to reduction for applicable withholding taxes.  As described more fully under "Performance Shares" in the CD&A and footnote (1) to the Grants of Plan-Based Awards table, performance shares will vest following a three-year performance period based on the extent to which the two 2014 performance conditions are achieved.  A total of 118,149  unearned performance shares (including accrued dividend equivalents) will vest on December 31, 2016, assuming achievement of these conditions at a target level of performance: (Mr. May: 55,638; Mr. Judge: 14,016; Mr. Olivier: 14,765; Mr. McHale: 14,016; Mr. Schweiger: 9,951 and Mr. Butler: 9,763).


(6)

The market value is determined by multiplying the number of performance shares in the adjacent column by $53.52, the closing price of NU common shares on December 31, 2014, the last trading day of the year.




160


OPTIONS EXERCISED AND STOCK VESTED IN 2014


The following table reports amounts realized on equity compensation during the fiscal year ended December 31, 2014.  The Stock Awards columns report the vesting of RSU grants to the Named Executive Officers in 2014.


 

 

Option Awards

 

Stock Awards

 

 

 

 

 

 

Number of

 

 

 

 

 

 

 

 

Shares

 

 

 

 

Number of

 

Value Realized

 

Acquired on

 

Value Realized

 

 

Shares Acquired

 

on Exercise

 

Vesting

 

on Vesting

Name

 

on Exercise

 

($) (1)

 

(#) (2)

 

($) (3)

Thomas J. May

 

649,440

 

11,654,253

 

90,002

 

3,864,352

James J. Judge

 

 

 

20,884

 

897,582

Leon J. Olivier

 

 

 

23,479

 

1,055,842

David R. McHale

 

 

 

22,300

 

1,002,842

Werner J. Schweiger

 

141,696

 

3,595,413

 

18,178

 

779,454

Gregory B. Butler

 

 

 

16,982

 

763,701


(1)

Represents the amounts realized upon option exercises, which is the difference between the option exercise price and the market price at the time of exercise.

(2)

Includes RSUs granted to the Named Executive Officers under NU's long-term incentive programs, including dividend reinvestments, as follows:


 

Name

 

2011 Program

 

2012 Program

 

2013 Program

 

2014 Program

 

Thomas J. May

 

37,191

 

34,867

 

17,944

 

 

James J. Judge

 

8,275

 

8,089

 

4,520

 

 

Leon J. Olivier

 

9,618

 

9,099

 

4,762

 

 

David R. McHale

 

9,136

 

8,644

 

4,520

 

 

Werner J. Schweiger

 

7,717

 

7,252

 

3,209

 

 

Gregory B. Butler

 

7,097

 

6,746

 

3,140

 


In all cases, the distribution of common shares is reduced by that number of shares valued in an amount sufficient to satisfy tax withholding obligations, which amount is distributed in cash.


(3)

Values realized on vesting for Messrs. May, Judge and Schweiger are based on $42.43 per share, the closing price of NU common shares on January 28, 2014 and $44.97 per share, the closing price of NU common shares on February 18, 2014.  Values realized on vesting for Messrs. Olivier, McHale and Butler are based on $44.42 per share, the closing price of NU common shares on February 25, 2014.


PENSION BENEFITS IN 2014


The Pension Benefits Table shows the estimated present value of accumulated retirement benefits payable to each Named Executive Officer upon retirement based on the assumptions described below.  The table distinguishes between benefits available under the qualified pension program, the supplemental pension program, and any additional benefits available under contractual agreements.  See the narrative above in the Compensation Discussion and Analysis under the caption "OTHER- Retirement Benefits" and "CONTRACTUAL AGREEMENTS" for more detail on benefits under these plans and our agreements.


The values shown in the Pension Benefits Table for Messrs. May and Judge were calculated as of December 31, 2014 based on benefit payments in the form of a lump sum. For Mr. McHale, a payment of benefits in the form of a one-half spousal contingent annuitant option was assumed. The Compensation Committee and the Board of Trustees approved a resolution in February of 2014 providing that the net present value of Mr. May's pension program benefit will be not less than the amount that represents the value of his earned pension program benefit as of December 31, 2012, the end of the year that Mr. May reached retirement age.  The retirement benefit equaled $23.05 million at that date. Such earned pension program benefit value could otherwise change in the future because of the reduction in mortality factors and the potentially rising interest rates.  For Mr. Olivier, both a lump sum payment of his special retirement benefits under his agreement, and payment of his qualified pension program benefit as a life annuity with a one-third spousal contingent annuitant option (the typical payment form under that Plan) were assumed.


The values shown in this Table for the Named Executive Officers were based on benefit payments commencing at the earliest possible ages for retirement with unreduced benefits: Mr. May: age 67, Mr. Judge: age 60, Mr. Olivier: age 60, Mr. McHale: age 60, Mr. Schweiger: age 60, Mr. Butler: age 62.  


In addition, benefits under the qualified pension program were determined using tax code limits in effect on December 31, 2014.  For Messrs. May, Judge and Schweiger, the values shown reflect actual 2014 salary and annual incentives earned in 2013 but paid in 2014 (per applicable supplemental program rules).  For Messrs. McHale and Butler, the values shown reflect actual 2014 salary and annual incentives earned in 2014 but paid in 2015 (per applicable supplemental program rules).  


The present value of benefits at retirement age was determined using the discount rate of 4.2 percent under ASC 715 for the 2014 fiscal year end measurement (as of December 31, 2014).  This present value assumes no pre-retirement mortality, turnover or disability.  However, for the postretirement period beginning at retirement age, we used the RP2000 Combined Healthy mortality table (the 1983 Group Annuity Mortality Table for Mr. Olivier per his agreement) as published by the Society of Actuaries projected to 2013 with projection scale AA, which is the same table used



161


for financial reporting under ASC 715.  Additional assumptions appear under the caption "Management's Discussion and Analysis and Results of Operations" in this Annual Report on Form 10-K.


Pension Benefits


 

 

 

 

Number of

 

Present Value

 

 

 

 

 

 

Years Credited

 

of Accumulation

 

During Last

Name

 

Plan Name

 

Service (#)

 

Benefit ($)

 

Fiscal Year ($)

Thomas J. May

 

Retirement Plan

 

38.5

 

2,332,334

 

 

 

Supplemental Plan

 

20

 

6,201,263

 

 

 

Supplemental Plan

 

38.5

 

14,704,089

 

James Judge

 

Retirement Plan

 

37.33

 

2,486,559

 

 

 

Supplemental Plan

 

20

 

4,642,887

 

 

 

Supplemental Plan

 

37.33

 

2,671,550

 

Leon J. Olivier (1)

 

Retirement Plan

 

15.8

 

702,330

 

 

 

Supplemental Plan

 

13.3

 

5,304,563

 

 

 

Special Retirement Benefit

 

31.2

 

1,266,068

 

105,966

David R. McHale

 

Retirement Plan

 

33.3

 

1,562,280

 

 

 

Supplemental Plan

 

33.3

 

5,994,100

 

Werner J. Schweiger

 

Retirement Plan

 

12.83

 

364,217

 

 

 

Supplemental Plan

 

12.83

 

3,860,859

 

 

 

Supplemental Plan

 

12.83

 

1,131,928

 

Gregory B. Butler

 

Retirement Plan

 

18

 

815,603

 

 

 

Supplemental Plan

 

18

 

2,314,489

 


(1)

Mr. Olivier was employed with Northeast Nuclear Energy Company, one of NU's subsidiaries, from October of 1998 through March of 2001.  In connection with this employment, he received a special retirement benefit that provided credit for service with his previous employer, Boston Edison Company (BECO), when calculating the value of his defined benefit pension, offset by the pension benefit provided by BECO.  The benefit, which commenced upon Mr. Olivier's 55th birthday, provides an annuity of $105,966 per year in a form that provides no contingent annuitant benefit.  The present value of future payments under this benefit was calculated using the actuarial assumptions currently used by the pension program.  Mr. Olivier was rehired by NU from Entergy in September 2001.  Mr. Olivier's current employment agreement provides for certain supplemental pension benefits in lieu of benefits under the supplemental program, in order to provide a benefit similar to that provided by Entergy.  Under this arrangement, Mr. Olivier is eligible to receive a supplemental benefit, consisting of three percent of final average compensation for each of his first 15 years of service since September 10, 2001, plus one percent of final average compensation for each of the second 15 years of service.  Alternatively, if Mr. Olivier voluntarily terminates his employment with NU, he is eligible to receive upon retirement a lump sum payment of $2,050,000 in lieu of benefits under the supplemental program and the benefit described in the preceding sentence.  These supplemental pension benefits will be offset by the value of any benefits he receives from the pension program.  Amounts reported in the table assume the termination of his employment with our consent on December 31, 2014, and payment of the lump sum benefit of $4,062,892 offset by pension program benefits.


NONQUALIFIED DEFERRED COMPENSATION IN 2014


See the narrative above in the Compensation Discussion and Analysis under the caption "ELEMENTS OF 2014 COMPENSATION - OTHER- Deferred Compensation" for more detail on our non-qualified deferred compensation program.  


 

 

Executive

 

Registrant

 

Aggregate

 

Aggregate

 

Aggregate

 

 

Contributions

 

Contributions

 

Earnings in

 

Withdrawals/

 

Balance at

 

 

in Last FY

 

in Last FY

 

in Last FY

 

Distributions

 

Last FYE

Name

 

($) (1)

 

($) (2)

 

($)

 

($) (3)

 

($) (4)

Thomas J. May

 

 

 

11,669,293

 

 

56,633,176

James J. Judge

 

 

 

1,008,682

 

 

4,380,935

Leon J. Olivier

 

123,446

 

10,737

 

186,165

 

 

2,901,959

David R. McHale

 

11,753

 

9,827

 

12,726

 

 

116,362

Werner J. Schweiger

 

997,803

 

 

1,457,325

 

 

13,782,734

Gregory B. Butler

 

 

 

2,826

 

 

16,087


(1)

Includes deferrals under the deferred compensation program (Mr. Olivier: $123,146; Mr. McHale: $11,753 and Mr. Schweiger: $997,803).  Named Executive Officers who participate in this program are provided with a variety of investment opportunities, which the individual can modify and reallocate under the program terms.  Contributions by the Named Executive Officer are vested at all times; however, the applicable employer matching contribution vests after three years and will be forfeited if the executive's employment terminates, other than for retirement, death or disability, prior to vesting, but will become fully vested upon a change of control.  The amounts reported in this column for each Named Executive Officer are reflected as compensation to such Named Executive Officer in the Summary Compensation Table.


(2)

Includes employer matching contributions made by NU under the deferred compensation program as of December 31, 2014 and posted on January 31, 2015, as reported in the All Other Compensation column of the Summary Compensation Table: (Mr. Olivier: $10,737 and Mr. McHale: $9,827).  The employer matching contribution is deemed to be invested in common shares but is paid in cash at the time of distribution.  



162



(3)

Includes the total market value of deferred compensation program balances at December 31, 2014, plus the value of vested RSUs or other awards for which the distribution of common shares is currently deferred, based on $53.52, the closing price of NU common shares on December 31, 2014, the last trading day of the year.  The aggregate balances reflect a significant level of earnings on previously earned and deferred compensation.


POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE OF CONTROL


Generally, a "change of control" means a change in ownership or control of NU effected through (i) the acquisition of 20 percent or more of the combined voting power of common shares or other voting securities (30 percent for Messrs. May, Judge and Schweiger, excluding certain defined transactions), (ii) the acquisition of more than 50 percent of common shares excluding certain defined transactions (for Messrs. May, Judge and Schweiger), (iii) a change in the majority of NU's Board of Trustees, unless approved by a majority of the incumbent Trustees, (iv) certain reorganizations, mergers or consolidations where substantially all of the persons who were the beneficial owners of the outstanding common shares immediately prior to such business combination do not beneficially own more than 50 percent (75 percent for Mr. Olivier) of the voting power of the resulting business entity (excluding in certain cases defined transactions), and (v) complete liquidation or dissolution of NU, or a sale or disposition of all or substantially all of the assets of NU other than, for Messrs. McHale and Butler, to an entity with respect to which following completion of the transaction more than 50 percent (75 percent for Mr. Olivier) of common shares or other voting securities is then owned by all or substantially all of the persons who were the beneficial owners of common shares and other voting securities immediately prior to such transaction.


In the event of a change of control, the Named Executive Officers are generally entitled to receive compensation and benefits following either involuntary termination of employment without "cause" or voluntary termination of employment for "good reason" within the applicable period (generally two years following change of control or shareholder approval thereof).  The Committee believes that termination for good reason is conceptually the same as termination "without cause" and, in the absence of this provision, potential acquirers would have an incentive to constructively terminate executives to avoid paying severance.  Termination for "cause" generally means termination due to a felony or certain other convictions; fraud, embezzlement, or theft in the course of employment; intentional, wrongful damage to Company property; gross misconduct or gross negligence in the course of employment or gross neglect of duties harmful to the Company; or a material breach of obligations under the agreement.  "Good reason" for termination generally exists after assignment of duties inconsistent with executive's position, a material reduction in compensation or benefits, a transfer more than 50 miles from the executive's pre-change of control principal business location (or for Messrs. May, Judge and Schweiger, an involuntary transfer outside the Greater Boston Metropolitan Area), or requiring business travel to a substantially greater extent than required pre-change of control (for Messrs. May, Judge and Schweiger).


The discussion and tables below show compensation payable to each Named Executive Officer, in the event of: (i) termination for cause; (ii) voluntary termination; (iii) involuntary not-for-cause termination; (iv) termination in the event of disability; (v) death; and (vi) termination following change of control.  The amounts shown assume that each termination was effective as of December 31, 2014, the last business day of the fiscal year.


The summaries above do not purport to be complete and are qualified in their entirety by the actual terms and provisions of the agreements and plans, copies of which have been filed as exhibits to this Annual Report on Form 10-K.


Payments Upon Termination


Regardless of the manner in which the employment of a Named Executive Officer terminates, he is entitled to receive certain amounts earned during his term of employment.  Such amounts include:


·

Vested RSUs and certain other vested awards;

·

Amounts contributed and any vested matching contributions under the deferred compensation program;

·

Pay for unused vacation; and

·

Amounts accrued and vested under the pension/supplemental and 401k programs (except in the event of a termination for cause under the supplemental program).


See the section above captioned "PENSION BENEFITS IN 2014" for information about the pension program, supplemental program and other benefits, and the section captioned "NONQUALIFIED DEFERRED COMPENSATION IN 2014."




163


I.

Post-Employment Compensation: Termination for Cause  


 

May

Judge

Olivier

McHale

Schweiger

Butler

Type of Payment

($)

($)

($)

($)

($)

($)

Incentive Programs

 

 

 

 

 

 

Annual Incentives

Performance Shares

RSUs

Pension and Deferred Compensation

 

 

 

 

 

 

Supplemental Plan

Special Retirement Benefit (1)

1,266,086

Deferral Plan

Other Benefits

 

 

 

 

 

 

Health and Welfare Cash Value

Perquisites

Separation Payments

 

 

 

 

 

 

Excise Tax & Gross-Up

Separation Payment for Non-Compete Agreement

Separation Payment for Liquidated Damages

             

             

             

             

             

             

Total

1,266,086


(1)

Represents actuarial present values at year-end 2014 of amounts payable solely under Mr. Olivier's employment agreement upon termination (which are in addition to amounts due under the pension program).  Under Mr. Olivier's agreement, he would receive upon termination a lump sum payment of $2,050,000, offset by the value of pension program benefits.  


II.

Post-Employment Compensation: Voluntary Termination


 

May

Judge

Olivier

McHale

Schweiger

Butler

Type of Payment

($)

($)

($)

($)

($)

($)

Incentive Programs

 

 

 

 

 

 

Annual Incentives (1)

2,250,000

660,000

680,000

660,000

600,000

515,000

Performance Shares (2)

6,069,829

728,740

1,509,336

515,450

505,971

RSUs (3)

4,819,597

438,797

1,689,294

309,770

646,586

Pension and Deferred Compensation

 

 

 

 

 

 

Supplemental Plan

Special Retirement Benefit (4)

1,266,086

 

Deferral Plan

Other Benefits

 

 

 

 

 

 

Health and Welfare Benefits

Perquisites

Separation Payments

 

 

 

 

 

 

Excise Tax & Gross-Up

Separation Payment for Non-Compete Agreement

Separation Payment for Liquidated Damages

             

             

             

             

             

             

Total

13,139,426

1,827,537

5,144,716

660,000

1,425,220

1,667,557


(1)

Represents actual 2014 annual incentive awards, determined as described in the CD&A.  


(2)

Represents performance share awards under the 2014 – 2016 Long-Term Incentive Program.  


(3)

Represents values of RSUs granted to the Named Executive Officers under NU's long-term incentive programs that, at year-end 2014, were unvested under applicable vesting schedules.  Under these programs, RSUs vest pro rata based on credited service years and age at termination, and time worked during the vesting period.  The values were calculated by multiplying the number of RSUs by $53.52, the closing price of NU common shares on December 31, 2014, the last trading day of the year.  Excludes retention pool RSU grants, which would not vest upon voluntary termination.


(4)

Represents actuarial present values at year-end 2014 of amounts payable solely under employment agreements (which are in addition to amounts due under the pension program).  Under Mr. Olivier's agreement, he would receive a lump sum payment of $2,050,000, offset by the value of pension program benefits.  Amounts shown are year-end 2014 present values payable upon termination.




164


III.

Post-Employment Compensation: Involuntary Termination, Not for Cause  


 

May

Judge

Olivier

McHale

Schweiger

Butler

Type of Payment

($)

($)

($)

($)

($)

($)

Incentive Programs

 

 

 

 

 

 

Annual Incentives (1)

2,250,000

660,000

680,000

660,000

600,000

515,000

Performance Shares (2)

6,069,829

728,740

1,509,336

515,450

505,971

RSUs (3)

6,748,237

5,021,218

4,653,230

1,997,345

4,398,447

2,087,901

Pension and Deferred Compensation

 

 

 

 

 

 

Supplemental Plan

Special Retirement Benefit (4)

1,266,086

4,063,886

3,570,713

Deferral Plan (5)

104,938

Other Benefits

 

 

 

 

 

 

Health and Welfare Benefits (6)

41,962

41,564

Perquisites (7)

10,000

10,000

Separation Payments

 

 

 

 

 

 

Excise Tax & Gross-Up

Separation Payment for Non-Compete Agreement (8)

 

977,295

761,310

Separation Payment for Liquidated Damages (9)

             

             

             

   977,295

             

   761,310

Total

15,068,066

6,409,958

8,108,652

8,832,721

5,513,897

8,253,769


(1)

Represents actual 2014 Named Executive Officer annual incentive awards, determined as described in the Compensation Discussion and Analysis.


(2)

Represents performance share awards under the 2014 - 2016 Long-Term Incentive Program.  


(3)

Represents values of RSUs under our long-term incentive programs that, at year-end 2014, were unvested under applicable vesting schedules.  Under these programs, RSUs vest pro rata based on credited service years and age at termination, and time worked during the vesting period.  Under the retention program, RSUs vest fully upon termination without cause and the value is reduced by separation payments.  The values were calculated by multiplying the number of RSUs by $53.52, the closing price of NU common shares on December 31, 2014, the last trading day of the year.  


(4)

Represents actuarial present values at year-end 2014 of amounts payable solely under employment agreements upon termination (which are in addition to amounts due under the pension program).  Mr. Olivier's agreement provides for a lump sum payment of $5,304,563 offset by the value of pension program benefits.  Agreements with Messrs. McHale and Butler provide for two years age and service credit under the supplemental program.


(5)

Represents value of NU matching contributions under the deferred compensation program that were unvested under applicable vesting schedules (other amounts in this program represent previously vested NU matching contributions, where applicable, and earned compensation contributed by executives).


(6)

Represents estimated costs to NU at year-end 2014 of providing post-employment welfare benefits beyond those available to non-executives upon involuntary termination.  The amount reported in the table for Messrs. McHale and Butler represents (a) the value of two years employer contributions toward active health, long-term disability, and life insurance benefits, plus (b) a payment to offset any taxes thereon (gross-up).  


(7)

Represents the cost to NU of reimbursing Messrs. McHale and Butler for two years financial planning and tax preparation fees.  


(8)

Represents consideration for agreements not to compete with NU following termination.  Employment agreements with these executives provide for a lump-sum payment equal to the sum of their base salary plus annual incentive award.  These payments do not replace, offset or otherwise affect the calculation or payment of the annual incentive awards.


(9)

Represents severance payments in addition to any non-compete agreement payments described in the prior note.  



165



IV.

Post-Employment Compensation: Termination Upon Disability


 

May

Judge

Olivier

McHale

Schweiger

Butler

Type of Payment

($)

($)

($)

($)

($)

($)

Incentive Programs

 

 

 

 

 

 

Annual Incentives (1)

2,250,000

660,000

680,000

660,000

600,000

515,000

Performance Shares (2)

6,069,829

728,740

1,509,336

728,740

515,450

505,971

RSUs and Other Awards (3)

6,748,237

5,021,218

4,653,230

4,829,027

4,398,447

3,610,521

Pension and Deferred Compensation

 

 

 

 

 

 

Supplemental Plan

Special Retirement Benefit (4)

1,266,086

Deferral Plan (5)

116,768

Other Benefits

 

 

 

 

 

 

Health and Welfare Benefits

Perquisites

Separation Payments

 

 

 

 

 

 

Excise Tax & Gross-Up

Separation Payment for Non-Compete Agreement

Separation Payment for Liquidated Damages

             

             

             

             

             

             

Total

15,068,066

6,409,958

8,108,652

6,334,535

5,513,897

4,631,492


(1)

Represents actual 2014 Named Executive Officer annual incentive awards, determined as described in the CD&A.


(2)

Represents performance share awards under the 2014 – 2016 Long-Term Incentive Program.  


(3)

Represents values of RSUs and other awards under our long-term incentive programs and retention awards that, at year-end 2014, were unvested under applicable vesting schedules.  Under these programs and awards, upon termination due to disability, awards vest in full or on a prorated basis based on credited service years and age at termination, and time worked during the vesting period.  The values were calculated by multiplying the number of RSUs by $53.52, the closing price of NU common shares on December 31, 2014, the last trading day of the year.


(4)

Represents the actuarial present values at the end of 2014 of the amounts payable solely as the result of employment agreements upon termination (which are in addition to amounts payable under the pension program).  Under Mr. Olivier's agreement, a disability termination results in a lump sum payment of $5,304,563 offset by the value of pension program benefits.  


(5)

Represents value of NU matching contributions under the deferred compensation program that were unvested under applicable vesting schedules (other amounts in this program represent previously vested NU matching contributions, where applicable, and earned compensation contributed by executives).


V.

Post-Employment Compensation:  Death


 

May

Judge

Olivier

McHale

Schweiger

Butler

Type of Payment

($)

($)

($)

($)

($)

($)

Incentive Programs

 

 

 

 

 

 

Annual Incentives (1)

2,250,000

660,000

680,000

660,000

600,000

515,000

Performance Shares (2)

6,069,829

728,740

1,509,336

728,740

515,450

505,971

RSUs and Other Awards (3)

6,748,237

5,021,218

4,653,230

4,829,027

4,398,447

3,610,521

Pension and Deferred Compensation

 

 

 

 

 

 

Supplemental Plan

Special Retirement Benefit (4)

1,266,086

Deferral Plan (5)

116,768

Other Benefits

 

 

 

 

 

 

Health and Welfare Benefits

Perquisites

Separation Payments

 

 

 

 

 

 

Excise Tax & Gross-Up

Separation Payment for Non-Compete Agreement

Separation Payment for Liquidated Damages

             

             

             

             

             

             

Total

15,068,066

6,409,958

8,108,652

6,334,535

5,513,897

4,631,492


(1)

Represents actual 2014 Named Executive Officer annual incentive awards, determined as described in the CD&A.


(2)

Represents performance share awards under the 2014 – 2016 Long-Term Incentive Program.  




166


(3)

Represents values of RSUs and other awards under our long-term incentive programs and retention awards that, at year-end 2014, were unvested under applicable vesting schedules.  Under these programs and awards, upon termination due to death, awards vest in full or are prorated based on credited service years and age at termination, and time worked during the vesting period.  The values were calculated by multiplying the number of RSUs by $53.52, the closing price of NU common shares on December 31, 2014, the last trading day of the year.


(4)

Represents the actuarial present values at the end of 2014 of the amounts payable to a surviving spouse solely under agreements (which are in addition to amounts due under the pension program).  Under Mr. Olivier's agreement, this benefit would be a lump sum payment of $5,304,563, offset by the value of pension program benefits. Pension amounts shown in the table are year-end 2014 present values of benefits immediately payable to the spouse or estate.  


(5)

Represents value of NU matching contributions under the deferred compensation program that were unvested under applicable vesting schedules (other amounts in this program represent previously vested NU matching contributions, where applicable, and earned compensation contributed by executives).


Payments Made Upon a Change of Control


The agreements with Messrs. May, Judge, McHale, Schweiger and Butler include change of control benefits.  Mr. Olivier participates in the Special Severance Program for Officers (SSP), which also provides change of control benefits.  The agreements and the SSP are binding on NU and on certain of its majority-owned subsidiaries, including CL&P.


Pursuant to the agreements and the SSP, if an involuntary non-"cause" termination of employment occurs following a change of control (see definition of "cause" above under the heading of "POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE OF CONTROL"), or in the event of a voluntary termination for "good reason" (as described above under such heading), then the Named Executive Officers generally will receive the benefits listed below:


·

For Messrs. May, Judge and Schweiger, a lump sum severance payment of three-times (two-times for Messrs. McHale and Butler, and one-time for Mr. Olivier) the sum of the executive's base salary plus annual incentive award for the relevant year (Base Compensation), plus for Messrs. McHale and Butler consideration for two year non-compete and non-solicitation covenants (one year covenant for Mr. Olivier) in the form of a lump sum payment equal to Base Compensation;  


·

Three years health benefits continuation (two years for Mr. Olivier);


·

For Messrs. McHale and Butler, three years additional age and service credit under the applicable supplemental pension program (a lump sum payment equal to the value of such credit under that program and the pension program for Messrs. May and Judge);  


·

Automatic vesting and distribution of long-term performance awards (with performance shares vesting at target) and certain other awards; and


·

A lump sum equal to any excise taxes incurred under the Internal Revenue Code due to receipt of change of control payments, plus an amount to offset any taxes incurred on such payments (gross-up) except for Mr. Olivier.  NU has discontinued the practice of providing such gross-up payments in contractual agreements for newly elected executives.


For Messrs. McHale and Butler, the Merger did not constitute a change of control under their agreements.  For Mr. Olivier, no compensation or benefits will be payable unless employment terminates during the applicable change of control period in the circumstances described below.  For Messrs. May, Judge and Schweiger, in accordance with terms established by the NSTAR Executive Personnel Committee subsequent to the execution of the Merger Agreement between NU and NSTAR, and notwithstanding the terms of the NSTAR Long Term Incentive Plan, which called for outstanding and unvested stock awards to vest upon a change of control, the 2012 NSTAR performance awards did not vest upon the closing of the Merger, but were instead converted to RSUs and were made subject to the same vesting schedule as NU RSUs.  No other benefits will be payable to these executives unless employment terminates during the applicable period in the circumstances described below.


The above summaries do not purport to be complete and are qualified in their entirety by the actual terms and provisions of the agreements and programs (including component plans), copies of which have been filed as exhibits to this Annual Report on Form 10-K (where applicable).




167


VI.

Post-Employment Compensation: Termination Following a Change of Control


 

May

Judge

Olivier

McHale

Schweiger

Butler

Type of Payment

($)

($)

($)

($)

($)

($)

Incentive Programs

 

 

 

 

 

 

Annual Incentives (1)

2,250,000

660,000

680,000

660,000

600,000

515,000

Performance Shares (2)

6,069,829

1,436,063

1,509,336

1,436,063

1,013,794

996,810

RSUs and Other Awards (3)

7,005,912

1,633,477

2,660,224

2,684,237

1,237,429

1,876,286

Pension and Deferred Compensation

 

 

 

 

 

 

Supplemental Plan

Special Retirement Benefit (4)

1,585,764

1,178,500

1,266,086

8,031,236

2,452,541

4,171,891

Deferral Plan (5)

116,768

Other Benefits

 

 

 

 

 

 

Health and Welfare Benefits (6)

30,168

63,054

27,864

62,942

63,429

62,345

Perquisites (7)

17,580

18,300

15,000

18,084

15,000

Separation Payments

 

 

 

 

 

 

Excise Tax and Gross-Up (8)

7,797,762

3,226,193

Separation Payment for Non-Compete Agreement (9)

1,026,465

977,295

761,310

Separation Payment for Liquidated Damages (10)

  9,990,300

3,726,900

1,026,465

  1,954,590

3,450,000

  1,522,620

Total

26,949,553

8,716,294

8,196,440

23,735,893

8,835,277

13,147,455


(1)

Represents actual 2014 annual incentive awards, determined as described in the CD&A.


(2)

Represents performance share awards under the 2014 – 2016 Long-Term Incentive Program.  


(3)

Represents values of RSUs and other awards under long-term incentive programs and retention awards that, at year-end 2014, were unvested under applicable vesting schedules.  Under these programs, upon termination in certain cases without cause or for good reason following a change of control, awards generally vest in full.  Retention awards vest in full in such circumstances, and the payout value is reduced by any separation payments as described above.  The values were calculated by multiplying the number of shares subject to awards by $53.52, the closing price of NU common shares on December 31, 2014, the last trading day of the year.


(4)

Represents actuarial present value at year-end 2014 of amounts payable solely as a result of provisions in employment agreements (which are in addition to amounts payable under the pension program).  For Messrs. May, Judge, McHale, Schweiger and Butler, pension benefits were calculated by adding three years of service (and a lump sum of this benefit value is payable to Messrs. May, Judge, Schweiger and Butler).  Mr. Olivier's agreement provides for a lump sum payment of $5,304,563, offset by his pension program benefit value.  Pension amounts shown in the table are present values at year-end 2014 of benefits payable upon termination as described with respect to the Pension Benefits Table above.


(5)

Represents value of NU matching contributions under the deferred compensation program that were unvested under applicable vesting schedules (other amounts in this program represent previously vested NU matching contributions, where applicable, and earned compensation contributed by executives).


(6)

Represents the cost to NU at year-end 2014 (estimated by our benefits consultants) of providing post-employment welfare benefits to Named Executive Officers beyond those benefits provided to non-executives upon involuntary termination.  The amounts shown in the table for Messrs. May, Judge and Schweiger represent the value of three years continued welfare plan participation.  The amounts shown in the table for Messrs. McHale and Butler represent (a) the value of three years employer contributions toward active health, long-term disability, and life insurance benefits, plus (b) a payment to offset any taxes on the value of these benefits (gross-up), less (c) the value of one year retiree health coverage at retiree rates.  The amounts reported in the table for Mr. Olivier represent (a) the value of two years employer contributions toward active health benefits, plus (b) a payment to offset any taxes on the value of these benefits (gross-up), less (c) the value of two years retiree health coverage at retiree rates.


(7)

Represents cost to NU of reimbursing financial planning and tax preparation fees for three years.


(8)

Represents payments made to offset costs to Messrs. McHale and Butler associated with certain excise taxes under Section 280G of the Internal Revenue Code.  Executives may be subject to certain excise taxes under Section 280G if they receive payments and benefits related to a termination following a Change of Control that exceed specified Internal Revenue Service limits.  Contractual agreements with the above executives provide for a grossed-up reimbursement of these excise taxes.  The amounts in the table are based on the Section 280G excise tax rate of 20 percent, the statutory federal income tax withholding rate of 35 percent, the applicable state income tax rate, and the Medicare tax rate of 1.45 percent.


(9)

Represents payments made under agreements or the SSP as consideration for agreement not to compete with NU following termination of employment equal to the sum of base salary plus relevant annual incentive award.  These payments do not replace, offset or otherwise affect the calculation or payment of the annual incentive awards.


(10)

Represents severance payments in addition to any non-compete agreement payments described in the prior note.  For Messrs. May, Judge and Schweiger, this payment equals three-times the sum of base salary plus relevant annual incentive award (two-times the sum for Messrs. McHale and Butler, and one-time the sum for Mr. Olivier.)  These payments do not replace, offset or otherwise affect the calculation or payment of the annual incentive awards.



168



Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters


NU


In addition to the information below under "Securities Authorized for Issuance Under Equity Compensation Plans," incorporated herein by reference is the information contained in the sections "Common Share Ownership of Certain Beneficial Owners" and "Common Share Ownership of Trustees and Management" of NU’s definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about March 13, 2015.


NSTAR ELECTRIC, PSNH and WMECO


Certain information required by this Item 12 has been omitted for NSTAR Electric, PSNH and WMECO pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly-Owned Subsidiaries.


CL&P


COMMON SHARE OWNERSHIP OF DIRECTORS AND MANAGEMENT


NU owns 100 percent of the outstanding common stock of CL&P.  The table below shows the number of NU common shares beneficially owned as of February 19, 2015, by each of CL&P’s directors and each Named Executive Officer of CL&P, as well as the number of NU common shares beneficially owned by all of CL&P’s directors and executive officers as a group.  The table also includes information about options, restricted share units and deferred shares credited to the accounts of CL&P’s directors and executive officers under certain compensation and benefit plans.  No equity securities of CL&P are owned by any of the Trustees, directors or executive officers of NU or CL&P.  The address for the shareholders listed below is c/o Northeast Utilities, Prudential Center, 800 Boylston Street, Boston, Massachusetts 02199 for Messrs. May, Judge and Schweiger and c/o Northeast Utilities, 56 Prospect Street, Hartford, Connecticut 06103-2818 for Messrs. Butler, McHale and Olivier.


Name of Beneficial Owner

 

Amount and Nature of
Beneficial Ownership (1)(2)(3)

 

Percent
of Class

Thomas J. May, Chairman of the Regulated Companies

 

1,644,902

 

 

*

Werner J. Schweiger, Chief Executive Officer, Director of the Regulated Companies

 

458,254

 

 

*

James J. Judge, Executive Vice President and Chief Financial Officer, Director of the Regulated Companies

 

308,597

 

 

*

Gregory B. Butler, Senior Vice President and General Counsel, Director of the Regulated Companies

 

159,446

(4)

 

*

David R. McHale, Executive Vice President and Chief Administrative Officer of NU and NUSCO

 

206,867

(5)

 

*

Leon J. Olivier, Executive Vice President-Enterprise Energy Strategy and Business Development of NU and NUSCO

 

205,483

 

 

*

All directors and executive officers as a group (10  persons)

 

3,275,512

(6)

 

1.0%


*

Less than 1 percent of NU common shares outstanding.

(1)

The persons named in the table have sole voting and investment power with respect to all shares beneficially owned by each of them, except as note below.


(2)

Includes NU common shares issuable upon exercise of outstanding stock options exercisable within the 60-day period after February 19, 2015, as follows: Mr. May:  174,496 shares; and Mr. Schweiger:  171,872 shares.  


Also includes restricted share units, deferred restricted share units and/or deferred shares, including dividend equivalents, as to which none of the individuals has voting or investment power, and phantom shares, representing employer matching contributions distributable only in cash, held by executive officers who participate in the Northeast Utilities Deferred Compensation Plan for Executives as follows; Mr. Butler:  84,837 shares; Mr. McHale:  115,827 shares; and Mr. Olivier:  102,118 shares.  Also includes restricted share units and/or unvested and vested deferred shares, as to which none of the individuals has voting or investment power, held by executive officers who participate in the NSTAR 2007 Long Term Incentive Plan, as follows:  Mr. Judge:  189,006 shares; Mr. May:  1,029,390 shares; and Mr. Schweiger:  206,140 shares.


Also includes unvested performance shares reported at target payouts, plus accumulated dividend equivalents, as to which none of the individuals has voting or investment power, as follows: Mr. Butler:  25,525 shares; Mr. Judge:  36,632 shares; Mr. May:  163,512 shares; Mr. McHale:  36,632 shares; Mr. Olivier:  38,501 shares; and Mr. Schweiger:  28,642 shares.  Actual payouts of the performance shares, if any, at the conclusion of relevant performance periods will depend on the extent to which performance goals are satisfied.


(3)

Includes NU common shares held as units in the 401(k) Plan invested in the NU Common Shares Fund over which the holder has sole voting and investment power (Mr. Butler: 4,862 shares; Mr. Judge: 22,598 shares; Mr. May: 66,197 shares; Mr. McHale: 7,422 shares; Mr. Olivier: 3,441 shares; and Mr. Schweiger: 8,719 shares).


(4)

Includes 44,222 NU common shares owned jointly by Mr. Butler and his spouse with whom he shares voting and investment power.


(5)

Includes 128 NU common shares held by Mr. McHale in the 401(k) Plan TRAESOP/PAYSOP account over which Mr. McHale has sole voting and investment power.



169



(6)

Includes 346,368 NU common shares issuable upon exercise of outstanding stock options exercisable within the 60-day period after February 19, 2015, and 2,295,072 unissued NU common shares.  See note 2.


SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS


The following table sets forth the number of NU common shares issuable under NU equity compensation plans, as well as their weighted exercise price, as of December 31, 2014, in accordance with the rules of the SEC:


Plan Category

 

Number of securities to be issued upon exercise of outstanding options, warrants and rights

(a)

 

Weighted-average exercise price of outstanding options, warrants and rights

(b)

 

Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))

(c)

Equity compensation plans approved by security holders

 

2,108,007

 

$26.69

 

3,888,995

Equity compensation plans not approved by security holders (d)

 

 

 

Total

 

2,108,007

 

$26.69

 

3,888,995


(a)

Includes 351,616 common shares to be issued upon exercise of options, 1,380,747 common shares for distribution of restricted share units, and 375,644 performance shares issuable at target, all pursuant to the terms of our Incentive Plans.  

(b)

The weighted-average exercise price in Column (b) does not take into account restricted share units or performance shares, which have no exercise price.

(c)

Includes 776,975 common shares issuable under our Employee Share Purchase Plan II.

(d)

All of our current compensation plans under which equity securities of NU are authorized for issuance have been approved by shareholders of NU or the former shareholders of NSTAR.


Item 13.

Certain Relationships and Related Transactions, and Director Independence


NU


Incorporated herein by reference is the information contained in the sections captioned "Trustee Independence" and "Certain Relationships and Related Transactions" of NU's definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about March 13, 2015.


NSTAR ELECTRIC, PSNH and WMECO


Certain information required by this Item 13 has been omitted for NSTAR Electric, PSNH and WMECO pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly-Owned Subsidiaries.


CL&P


NU's Code of Ethics for Senior Financial Officers applies to the Senior Financial Officers (Chief Executive Officer, Chief Financial Officer and Controller) of NU, CL&P and certain other NU subsidiaries.  Under the Code, one's position as a Senior Financial Officer in the company may not be used to improperly benefit such officer or his or her family or friends.  Under the Code, specific activities that may be considered conflicts of interest include, but are not limited to, directly or indirectly acquiring or retaining a significant financial interest in an organization that is a customer, vendor or competitor, or that seeks to do business with the company; serving, without proper safeguards, as an officer or director of, or working or rendering services for an organization that is a customer, vendor or competitor, or that seeks to do business with the company. Waivers of the provisions of the Code of Ethics for Trustees, executive officers or directors must be approved by NU's Board of Trustees.  Any such waivers will be disclosed pursuant to legal requirements.


NU's Code of Business Conduct, which applies to all Trustees, directors, officers and employees of NU and its subsidiaries, including CL&P, contains a Conflict of Interest Policy that requires all such individuals to disclose any potential conflicts of interest.  Such individuals are expected to discuss their particular situations with management to ensure appropriate steps are in place to avoid a conflict of interest.  All disclosures must be reviewed and approved by management to ensure a particular situation does not adversely impact the individual's primary job and role.


NU's Related Party Transactions Policy is administered by the Corporate Governance Committee of NU's Board of Trustees.  The Policy generally defines a "Related Party Transaction" as any transaction or series of transactions in which (i) NU or a subsidiary is a participant, (ii) the aggregate amount involved exceeds $120,000 and (iii) any "Related Party" has a direct or indirect material interest.  A "Related Party" is defined as any Trustee or nominee for Trustee, any executive officer, any shareholder owning more than 5 percent of NU's total outstanding shares, and any immediate family member of any such person.  Management submits to the Corporate Governance Committee for consideration any Related Party Transaction into which NU or a subsidiary proposes to enter.  The Corporate Governance Committee recommends to the NU Board of Trustees for approval only those transactions that are in NU's best interests.  If management causes the company to enter into a Related Party Transaction prior to approval by the Corporate Governance Committee, the transaction will be subject to ratification by the NU Board of Trustees.  If the NU Board of Trustees determines not to ratify the transaction, then management will make all reasonable efforts to cancel or annul such transaction.



170



The directors of CL&P are employees of CL&P and/or other subsidiaries of NU, and thus are not considered independent.


Item 14.

Principal Accountant Fees and Services


NU


Incorporated herein by reference is the information contained in the section "Relationship with Independent Auditors" of NU's definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about March 13, 2015.


CL&P, NSTAR ELECTRIC, PSNH and WMECO


Pre-Approval of Services Provided by Principal Auditors


None of CL&P, NSTAR Electric, PSNH or WMECO is subject to the audit committee requirements of the SEC, the national securities exchanges or the national securities associations.  CL&P, NSTAR Electric, PSNH and WMECO obtain audit services from the independent auditor engaged by the Audit Committee of NU's Board of Trustees.  NU's Audit Committee has established policies and procedures regarding the pre-approval of services provided by the principal auditors.  Those policies and procedures delegate pre-approval of services to the NU Audit Committee Chair provided that such offices are held by Trustees who are "independent" within the meaning of the Sarbanes-Oxley Act of 2002 and that all such pre-approvals are presented to the NU Audit Committee at the next regularly scheduled meeting of the Committee.


The following relates to fees and services for the entire NU system, including NU, CL&P, NSTAR Electric, PSNH and WMECO.


Fees Billed by Principal Independent Registered Public Accounting Firm


The aggregate fees billed to NU and its subsidiaries by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates (collectively, the Deloitte Entities), for the years ended December 31, 2014 and 2013 totaled $3,986,500 and $3,616,225, respectively.  In addition, affiliates of Deloitte & Touche LLP as noted below provide other accounting services to NU.  Fees were comprised of the following:


1.

Audit Fees


The aggregate fees billed to NU and its subsidiaries by Deloitte & Touche LLP for audit services rendered for the years ended December 31, 2014 and 2013 totaled $3,775,000 and $3,493,925, respectively.  The audit fees were incurred for audits of Northeast Utilities' annual consolidated financial statements and those of its subsidiaries, reviews of financial statements included in Northeast Utilities' Quarterly Reports on Form 10-Q and those of its subsidiaries, comfort letters, consents and other costs related to registration statements and financings.  The fees also included audits of internal controls over financial reporting as of December 31, 2014 and 2013.  


2.

Audit Related Fees


The aggregate fees billed to NU and its subsidiaries by the Deloitte Entities for audit related services rendered for the years ended December 31, 2014 and 2013 totaled $175,000 and $100,000, respectively.  The audit related fees were incurred for procedures performed in the ordinary course of business in support of certain regulatory filings.


3.

Tax Fees


The aggregate fees billed to NU and its subsidiaries by the Deloitte Entities for tax services for the year ended December 31, 2013 totaled $20,800.  Tax fees for 2013 related primarily to reviews of tax returns.  There were no tax fees for the year ended December 31, 2014.


4.

All Other Fees


The aggregate fees billed to NU and its subsidiaries by the Deloitte Entities for services other than the services described above for the years ended December 31, 2014 and 2013 totaled $36,500 and $1,500, respectively.   The 2014 fees include $35,000 for an IT security assessment and both the 2014 and 2013 fees include $1,500 for a license for access to an accounting standards research tool.


NU's Audit Committee pre-approves all auditing services and permitted audit related or other services (including the fees and terms thereof) to be performed for us by our independent registered public accounting firm, subject to the de minimis exceptions for non-audit services described in Section 10A(i)(1)(B) of the Securities Exchange Act of 1934, which are approved by the Audit Committee prior to the completion of the audit.  The Audit Committee may form and delegate its authority to subcommittees consisting of one or more members when appropriate, including the authority to grant pre-approvals of audit and permitted non-audit services, provided that decisions of such subcommittee to grant pre-approvals are presented to the full Audit Committee at its next scheduled meeting.  During 2014, all services described above were pre-approved by the Audit Committee.  


NU's Audit Committee has considered whether the provision by the Deloitte Entities of the non-audit services described above was allowed under Rule 2-01(c)(4) of Regulation S-X and was compatible with maintaining the independence of the registered public accountants and has concluded that the Deloitte Entities were and are independent of us in all respects.




























































































171



PART IV

Item 15.

Exhibits and Financial Statement Schedules


 

 

 

 

(a)

1.

Financial Statements:

 

 

 

 

 

 

 

 

The financial statements filed as part of this Annual Report on Form 10-K are set forth under Item 8, "Financial Statements and Supplementary Data."  

 

 

 

 

 

 

 

2.

Schedules

 

 

 

 

 

 

 

 

I.

Financial Information of Registrant:
Northeast Utilities (Parent) Balance Sheets as of December 31, 2014 and 2013

S-1

 

 

 

 

 

 

 

 

Northeast Utilities (Parent) Statements of Income for the Years Ended
December 31, 2014, 2013 and 2012

S-2

 

 

 

 

 

 

 

 

Northeast Utilities (Parent) Statements of Comprehensive Income for the Years Ended December 31, 2014, 2013 and 2012

S-2

 

 

 

 

 

 

 

 

Northeast Utilities (Parent) Statements of Cash Flows for the Years Ended
December 31, 2014, 2013 and 2012

S-3

 

 

 

 

 

 

 

II.

Valuation and Qualifying Accounts and Reserves for NU, CL&P, NSTAR Electric, PSNH and WMECO for 2014, 2013 and 2012

S-4

 

 

 

 

 

 

 

 

All other schedules of the companies for which inclusion is required in the applicable regulations of the SEC are permitted to be omitted under the related instructions or are not applicable, and therefore have been omitted.

 

 

 

 

 

 

 

3.

 

Exhibit Index

E-1




172


NORTHEAST UTILITIES


SIGNATURES


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

 

 

 

 

February 25, 2015

By:

/s/

Jay S. Buth

 

 

 

Jay S. Buth

 

 

 

Vice President, Controller and Chief Accounting Officer


Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.


POWER OF ATTORNEY


Each person whose signature appears below constitutes and appoints Gregory B. Butler, James J. Judge and Jay S. Buth and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.


Signature

 

Title

 

Date

 

 

 

 

 

/s/

Thomas J. May

 

Chairman, President and

 

February 25, 2015

Thomas J. May

 

Chief Executive Officer, and a Trustee

 

 

 

 

(Principal Executive Officer)

 

 

 

 

 

 

 

 

 

 

 

 

/s/

James J. Judge

 

Executive Vice President and

 

February 25, 2015

James J Judge

 

Chief Financial Officer

 

 

 

 

(Principal Financial Officer)

 

 

 

 

 

 

 

 

 

 

 

 

/s/

Jay S. Buth

 

Vice President, Controller

 

February 25, 2015

Jay S. Buth

 

and Chief Accounting Officer

 

 

 

 

 

 

 

 

 

 

 

 

/s/

Richard H. Booth

 

Trustee

 

February 25, 2015

Richard H. Booth

 

 

 

 

 

 

 

 

 

 

 

 

 

 

/s/

John S. Clarkeson

 

Trustee

 

February 25, 2015

John S. Clarkeson

 

 

 

 

 

 

 

 

 

 

 

 

 

 

/s/

Cotton M. Cleveland

 

Trustee

 

February 25, 2015

Cotton M. Cleveland

 

 

 

 

 

 

 

 

 

 

 

 

 

 

/s/

Sanford Cloud, Jr.

 

Trustee

 

February 25, 2015

Sanford Cloud, Jr.

 

 

 

 

 

 

 

 

 


/s/

James S. DiStasio

 

Trustee

 

February 25, 2015

James S. DiStasio

 

 

 

 

 

 

 

 

 

 

 

 

 

 

/s/

Francis A. Doyle

 

Trustee

 

February 25, 2015

Francis A. Doyle

 

 

 

 

 

 

 

 

 



173



 

 

 

 

 

/s/

Charles K. Gifford

 

Trustee

 

February 25, 2015

Charles K. Gifford

 

 

 

 

 

 

 

 

 

 

 

 

 

 

/s/

Paul A. La Camera

 

Trustee

 

February 25, 2015

Paul A. La Camera

 

 

 

 

 

 

 

 

 

 

 

 

 

 

/s/

Kenneth R. Leibler

 

Trustee

 

February 25, 2015

Kenneth R. Leibler

 

 

 

 

 

 

 

 

 

 

 

 

 

 

/s/

William C. Van Faasen

 

Trustee

 

February 25, 2015

William C. Van Faasen

 

 

 

 

 

 

 

 

 

 

 

 

 

 

/s/

Frederica M. Williams

 

Trustee

 

February 25, 2015

Frederica M. Williams

 

 

 

 

 

 

 

 

 

 

 

 

 

 

/s/

Dennis R. Wraase

 

Trustee

 

February 25, 2015

Dennis R. Wraase

 

 

 

 

 

 

 

 

 




174



THE CONNECTICUT LIGHT AND POWER COMPANY


SIGNATURES


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

 

 

 

 

February 25, 2015

By:

/s/

Jay S. Buth

 

 

 

Jay S. Buth

 

 

 

Vice President, Controller and Chief Accounting Officer


Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.


POWER OF ATTORNEY


Each person whose signature appears below constitutes and appoints Gregory B. Butler, James J. Judge and Jay S. Buth and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.


Signature

 

Title

 

Date


 

 

 

 

/s/

Thomas J. May

 

Chairman and a Director

 

February 25, 2015

Thomas J. May

 

(Principal Executive Officer)

 

 

 

 

 

 

 

 

 

 

 

 

/s/

Werner J. Schweiger

 

Chief Executive Officer and a Director

 

February 25, 2015

Werner J. Schweiger

 

 

 

 

 

 

 

 

 

 

 

 

 

 

/s/

James J. Judge

 

Executive Vice President and

 

February 25, 2015

James J. Judge

 

Chief Financial Officer and a Director

 

 

 

 

(Principal Financial Officer)

 

 

 

 

 

 

 

 

 

 

 

 

/s/

Gregory B. Butler

 

Senior Vice President and General Counsel

 

February 25, 2015

Gregory B. Butler

 

and a Director

 

 

 

 

 

 

 

 

 

 

 

 

/s/

Jay S. Buth

 

Vice President, Controller

 

February 25, 2015

Jay S. Buth

 

and Chief Accounting Officer

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 



























































































175



NSTAR ELECTRIC COMPANY


SIGNATURES


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

 

 

 

 

February 25, 2015

By:

/s/

Jay S. Buth

 

 

 

Jay S. Buth

 

 

 

Vice President, Controller and Chief Accounting Officer


Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.


POWER OF ATTORNEY


Each person whose signature appears below constitutes and appoints Gregory B. Butler, James J. Judge and Jay S. Buth and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.


Signature

 

Title

 

Date


 

 

 

 

/s/

Thomas J. May

 

Chairman and a Director

 

February 25, 2015

Thomas J. May

 

(Principal Executive Officer)

 

 

 

 

 

 

 

 

 

 

 

 

/s/

Werner J. Schweiger

 

Chief Executive Officer and a Director

 

February 25, 2015

Werner J. Schweiger

 

 

 

 

 

 

 

 

 

 

 

 

 

 

/s/

James J. Judge

 

Executive Vice President and

 

February 25, 2015

James J. Judge

 

Chief Financial Officer and a Director

 

 

 

 

(Principal Financial Officer)

 

 

 

 

 

 

 

 

 

 

 

 

/s/

Gregory B. Butler

 

Senior Vice President and General Counsel

 

February 25, 2015

Gregory B. Butler

 

and a Director

 

 

 

 

 

 

 

 

 

 

 

 

/s/

Jay S. Buth

 

Vice President, Controller

 

February 25, 2015

Jay S. Buth

 

and Chief Accounting Officer

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 



























































































176



PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE


SIGNATURES


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

 

 

 

 

February 25, 2015

By:

/s/

Jay S. Buth

 

 

 

Jay S. Buth

 

 

 

Vice President, Controller and Chief Accounting Officer


Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.


POWER OF ATTORNEY


Each person whose signature appears below constitutes and appoints Gregory B. Butler, James J. Judge and Jay S. Buth and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.


Signature

 

Title

 

Date


 

 

 

 

/s/

Thomas J. May

 

Chairman and a Director

 

February 25, 2015

Thomas J. May

 

(Principal Executive Officer)

 

 

 

 

 

 

 

 

 

 

 

 

/s/

Werner J. Schweiger

 

Chief Executive Officer and a Director

 

February 25, 2015

Werner J. Schweiger

 

 

 

 

 

 

 

 

 

 

 

 

 

 

/s/

James J. Judge

 

Executive Vice President and

 

February 25, 2015

James J. Judge

 

Chief Financial Officer and a Director

 

 

 

 

(Principal Financial Officer)

 

 

 

 

 

 

 

 

 

 

 

 

/s/

Gregory B. Butler

 

Senior Vice President and General Counsel

 

February 25, 2015

Gregory B. Butler

 

and a Director

 

 

 

 

 

 

 

 

 

 

 

 

/s/

Jay S. Buth

 

Vice President, Controller

 

February 25, 2015

Jay S. Buth

 

and Chief Accounting Officer

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 




177


WESTERN MASSACHUSETTS ELECTRIC COMPANY


SIGNATURES


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

 

 

 

 

February 25, 2015

By:

/s/

Jay S. Buth

 

 

 

Jay S. Buth

 

 

 

Vice President, Controller and Chief Accounting Officer


Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.


POWER OF ATTORNEY


Each person whose signature appears below constitutes and appoints Gregory B. Butler, James J. Judge and Jay S. Buth  and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.


Signature

 

Title

 

Date


 

 

 

 

/s/

Thomas J. May

 

Chairman and a Director

 

February 25, 2015

Thomas J. May

 

(Principal Executive Officer)

 

 

 

 

 

 

 

 

 

 

 

 

/s/

Werner J. Schweiger

 

Chief Executive Officer and a Director

 

February 25, 2015

Werner J. Schweiger

 

 

 

 

 

 

 

 

 

 

 

 

 

 

/s/

James J. Judge

 

Executive Vice President and

 

February 25, 2015

James J. Judge

 

Chief Financial Officer and a Director

 

 

 

 

(Principal Financial Officer)

 

 

 

 

 

 

 

 

 

 

 

 

/s/

Gregory B. Butler

 

Senior Vice President and General Counsel

 

February 25, 2015

Gregory B. Butler

 

and a Director

 

 

 

 

 

 

 

 

 

 

 

 

/s/

Jay S. Buth

 

Vice President, Controller

 

February 25, 2015

Jay S. Buth

 

and Chief Accounting Officer

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 





178



SCHEDULE I

NORTHEAST UTILITIES (PARENT)

FINANCIAL INFORMATION OF REGISTRANT

BALANCE SHEETS

AS OF DECEMBER 31, 2014 AND 2013

(Thousands of Dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

2014 

 

2013 

ASSETS

 

 

 

 

 

Current Assets:

 

 

 

 

 

 

Cash

$

 138 

 

$

 35 

 

Accounts Receivable from Subsidiaries

 

 6,725 

 

 

 95,513 

 

Notes Receivable from Subsidiaries

 

 741,150 

 

 

 871,050 

 

Prepayments and Other Current Assets

 

 41,366 

 

 

 59,905 

Total Current Assets

 

 789,379 

 

 

 1,026,503 

 

 

 

 

 

 

 

 

 

Deferred Debits and Other Assets:

 

 

 

 

 

 

Investments in Subsidiary Companies, at Equity

 

 8,387,976 

 

 

 7,733,051 

 

Notes Receivable from Subsidiaries

 

 106,300 

 

 

 62,500 

 

Accumulated Deferred Income Taxes

 

 177,908 

 

 

 205,779 

 

Goodwill

 

 3,231,811 

 

 

 3,231,811 

 

Other Long-Term Assets

 

 33,552 

 

 

 22,099 

Total Deferred Debits and Other Assets

 

 11,937,547 

 

 

 11,255,240 

 

 

 

 

 

 

 

 

 

Total Assets

$

 12,726,926 

 

$

 12,281,743 

 

 

 

 

 

 

 

 

 

LIABILITIES AND CAPITALIZATION

 

 

 

 

 

Current Liabilities:

 

 

 

 

 

 

Notes Payable

$

 654,825 

 

$

 1,014,500 

 

Long-Term Debt - Current Portion

 

 28,883 

 

 

 31,696 

 

Accounts Payable

 

 141 

 

 

 441 

 

Accounts Payable to Subsidiaries

 

 150,268 

 

 

 144,026 

 

Other

 

 71,778 

 

 

 59,559 

Total Current Liabilities

 

 905,895 

 

 

 1,250,222 

 

 

 

 

 

 

 

 

 

Deferred Credits and Other Liabilities:

 

 

 

 

 

 

Other

 

 125,608 

 

 

 122,226 

Total Deferred Credits and Other Liabilities

 

 125,608 

 

 

 122,226 

 

 

 

 

 

 

 

 

 

Capitalization:

 

 

 

 

 

 

Long-Term Debt

 

 1,718,608 

 

 

 1,297,767 

 

 

 

 

 

 

 

 

 

 

Equity:

 

 

 

 

 

 

 

Common Shareholders' Equity:

 

 

 

 

 

 

 

 

Common Shares

 

 1,666,796 

 

 

 1,665,351 

 

 

 

Capital Surplus, Paid in

 

 6,235,834 

 

 

 6,192,765 

 

 

 

Retained Earnings

 

 2,448,661 

 

 

 2,125,980 

 

 

 

Accumulated Other Comprehensive Loss

 

 (74,009)

 

 

 (46,031)

 

 

 

Treasury Stock

 

 (300,467)

 

 

 (326,537)

 

 

Common Shareholders' Equity

 

 9,976,815 

 

 

 9,611,528 

Total Capitalization

 

 11,695,423 

 

 

 10,909,295 

 

 

 

 

 

 

 

 

 

Total Liabilities and Capitalization

$

 12,726,926 

 

$

 12,281,743 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

See the Combined Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for a description of significant accounting matters related to NU parent, including NU common shares information as described in Note 16, "Common Shares," material obligations and guarantees as described in Note 11, "Commitments and Contingencies," and debt agreements as described in Note 7, "Short-Term Debt," and Note 8, "Long-Term Debt."




S-1



SCHEDULE I

NORTHEAST UTILITIES (PARENT)

FINANCIAL INFORMATION OF REGISTRANT

STATEMENTS OF INCOME

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013 AND 2012

(Thousands of Dollars, Except Share Information)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014 

 

2013 

 

2012 (1)

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

$

 - 

 

$

 8 

 

$

 2 

 

 

 

 

 

 

 

 

 

 

 

Operating Expenses:

 

 

 

 

 

 

 

 

 

Other

 

 29,598 

 

 

 12,766 

 

 

 80,719 

Operating Loss

 

 (29,598)

 

 

 (12,758)

 

 

 (80,717)

Interest Expense

 

 33,168 

 

 

 31,639 

 

 

 36,325 

 

 

 

 

 

 

 

 

 

 

 

Other Income, Net:

 

 

 

 

 

 

 

 

 

Equity in Earnings of Subsidiaries

 

 848,435 

 

 

 785,650 

 

 

 579,221 

 

Other, Net

 

 1,830 

 

 

 5,062 

 

 

 6,080 

 

 

Other Income, Net

 

 850,265 

 

 

 790,712 

 

 

 585,301 

Income Before Income Tax Benefit

 

 787,499 

 

 

 746,315 

 

 

 468,259 

Income Tax Benefit

 

 (32,047)

 

 

 (39,692)

 

 

 (57,789)

Net Income

 

 819,546 

 

 

 786,007 

 

 

 526,048 

Net Income Attributable to Noncontrolling Interest

 

 - 

 

 

 - 

 

 

 103 

Net Income Attributable to Controlling Interest

$

 819,546 

 

$

 786,007 

 

$

 525,945 

 

 

 

 

 

 

 

 

 

 

 

Basic Earnings per Common Share

$

 2.59 

 

$

 2.49 

 

$

 1.90 

 

 

 

 

 

 

 

 

 

 

 

Diluted Earnings per Common Share

$

 2.58 

 

$

 2.49 

 

$

 1.89 

 

 

 

 

 

 

 

 

 

 

 

Weighted Average Common Shares Outstanding:

 

 

 

 

 

 

 

 

 

Basic

 

 316,136,748 

 

 

 315,311,387 

 

 

 277,209,819 

 

Diluted

 

 317,417,414 

 

 

 316,211,160 

 

 

 277,993,631 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

STATEMENTS OF COMPREHENSIVE INCOME

 

 

 

 

 

 

 

 

 

 

 

Net Income

$

 819,546 

 

$

 786,007 

 

$

 526,048 

Other Comprehensive Income/(Loss), Net of Tax:

 

 

 

 

 

 

 

 

 

Qualified Cash Flow Hedging Instruments

 

 2,037 

 

 

 2,049 

 

 

 1,971 

 

Changes in Unrealized Gains/(Losses) on Other Securities

 

 315 

 

 

 (940)

 

 

 217 

 

Change in Funded Status of Pension, SERP and PBOP

 

 

 

 

 

 

 

 

 

 

Benefit Plans

 

 (30,330)

 

 

 25,714 

 

 

 (4,356)

Other Comprehensive Income/(Loss), Net of Tax

 

 (27,978)

 

 

 26,823 

 

 

 (2,168)

Comprehensive Income Attributable to Noncontrolling Interest

 

 - 

 

 

 - 

 

 

 (103)

Comprehensive Income Attributable to Controlling Interest

$

 791,568 

 

$

 812,830 

 

$

 523,777 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1) On April 10, 2012, NU acquired NSTAR and its subsidiaries.  The financial information includes NSTAR and its subsidiaries' results of operations beginning April 10, 2012.  See Note 21, "Merger of NU and NSTAR," for further information regarding the merger.  

 

 

 

 

 

 

 

 

 

 

 

See the Combined Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for a description of significant accounting matters related to NU parent, including NU common shares information as described in Note 16, "Common Shares," material obligations and guarantees as described in Note 11, "Commitments and Contingencies," and debt agreements as described in Note 7, "Short-Term Debt," and Note 8, "Long-Term Debt."




S-2



SCHEDULE I

NORTHEAST UTILITIES (PARENT)

FINANCIAL INFORMATION OF REGISTRANT

STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013 and 2012

(Thousands of Dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

2013

 

2012 (1)

Operating Activities:

 

 

 

 

 

 

 

 

 

Net Income

$

 819,546 

 

$

 786,007 

 

$

 526,048 

 

Adjustments to Reconcile Net Income to Net Cash

 

 

 

 

 

 

 

 

 

 

Flows Provided by Operating Activities:

 

 

 

 

 

 

 

 

 

 

 

Equity in Earnings of Subsidiaries

 

 (848,435)

 

 

 (785,650)

 

 

 (579,221)

 

 

 

Cash Dividends Received from Subsidiaries

 

 609,800 

 

 

 407,837 

 

 

 374,584 

 

 

 

Deferred Income Taxes

 

 7,956 

 

 

 15,159 

 

 

 (15,350)

 

 

 

Other

 

 9,409 

 

 

 29,169 

 

 

 (3,755)

 

 

Changes in Current Assets and Liabilities:

 

 

 

 

 

 

 

 

 

 

 

Accounts Receivables from Subsidiaries

 

 88,800 

 

 

 14,704 

 

 

 (18,321)

 

 

 

Taxes Receivable/Accrued, Net

 

 23,178 

 

 

 13,295 

 

 

 (16,872)

 

 

 

Accounts Payable, Including Affiliate Payables

 

 5,942 

 

 

 (7,058)

 

 

 48,332 

 

 

 

Other Current Assets and Liabilities, Net

 

 14,484 

 

 

 (1,411)

 

 

 60,182 

Net Cash Flows Provided by Operating Activities

 

 730,680 

 

 

 472,052 

 

 

 375,627 

 

 

 

 

 

 

 

 

 

 

 

 

Investing Activities:

 

 

 

 

 

 

 

 

 

Capital Contributions to Subsidiaries

 

 (437,553)

 

 

 (65,400)

 

 

 (81,431)

 

Return of Investment in Subsidiaries

 

 - 

 

 

 - 

 

 

 8,207 

 

Decrease in Money Pool Lending

 - 

 

 

 - 

 

 

 2,200 

 

Decrease/(Increase) in Notes Receivable from Subsidiaries

 

 86,100 

 

 

 5,475 

 

 

 (704,475)

 

Other Investing Activities

 

 - 

 

 

 (1,862)

 

 

 (608)

Net Cash Flows Used in Investing Activities

 

 (351,453)

 

 

 (61,787)

 

 

 (776,107)

 

 

 

 

 

 

 

 

 

 

 

 

Financing Activities:

 

 

 

 

 

 

 

 

 

Cash Dividends on Common Shares

 

 (475,227)

 

 

 (462,741)

 

 

 (375,047)

 

Issuance of Long-Term Debt

 

 - 

 

 

 750,000 

 

 

 300,000 

 

Retirement of Long-Term Debt

 

 - 

 

 

 (550,000)

 

 

 (263,000)

 

Increase/(Decrease) in Short-Term Debt

 

 86,575 

 

 

 (135,500)

 

 

 733,500 

 

Other Financing Activities

 

 9,528 

 

 

 (12,418)

 

 

 5,394 

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

 

 (379,124)

 

 

 (410,659)

 

 

 400,847 

Net Increase/(Decrease) in Cash

 

 103 

 

 

 (394)

 

 

 367 

Cash - Beginning of Year

 

 35 

 

 

 429 

 

 

 62 

Cash - End of Year

$

 138 

 

$

 35 

 

$

 429 

 

 

 

 

 

 

 

 

 

 

 

 

Supplemental Cash Flow Information:

 

 

 

 

 

 

 

 

Cash Paid/(Received) During the Year for:

 

 

 

 

 

 

 

 

 

Interest

$

 36,208 

 

$

 33,822 

 

$

 50,144 

 

Income Taxes

$

 (86,804)

 

$

 (30,603)

 

$

 (27,126)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1) On April 10, 2012, NU acquired NSTAR and its subsidiaries.  The financial information includes NSTAR and its subsidiaries' cash flows beginning April 10, 2012.  See Note 21, "Merger of NU and NSTAR," for further information regarding the merger.  

 

 

 

 

 

 

 

 

 

 

 

 

See the Combined Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for a description of significant accounting matters related to NU parent, including NU common shares information as described in Note 16, "Common Shares," material obligations and guarantees as described in Note 11, "Commitments and Contingencies," and debt agreements as described in Note 7, "Short-Term Debt," and Note 8, "Long-Term Debt."




S-3



SCHEDULE II

NORTHEAST UTILITIES AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013 AND 2012

(Thousands of Dollars)

 

Column A

Column B

 

Column C

 

Column D

 

Column E

 

 

 

 

 

 

Additions

 

 

 

 

 

 

 

 

 

 

 

(1)

 

(2)

 

(3)

 

 

 

 

 

 

 

 

 

 

 

Charged

 

Charged to

 

Impact

 

 

 

 

 

 

 

 

Balance as

 

to Costs

 

Other

 

Related to

 

Deductions -

 

Balance

 

 

of Beginning

 

and

 

Accounts -

 

Merger With

 

Describe

 

as of

Description:

of Year

 

Expenses

 

Describe (a)

 

NSTAR

 

(b)

 

End of Year

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NU:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reserves Deducted from Assets -

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reserves for Uncollectible Accounts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014 

$

 171,251 

 

$

 55,657 

 

$

 51,227 

 

$

 - 

 

$

 102,818 

 

$

 175,317 

 

2013 

 

 165,549 

 

 

 55,465 

 

 

 37,744 

 

 

 - 

 

 

 87,507 

 

 

 171,251 

 

2012 

 

 115,689 

 

 

 36,275 

 

 

 34,761 

 

 

 59,286 

 

 

 80,462 

 

 

 165,549 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CL&P:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reserves Deducted from Assets -

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reserves for Uncollectible Accounts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014 

$

 81,995 

 

$

 6,598 

 

$

 39,706 

 

$

 - 

 

$

 44,012 

 

$

 84,287 

 

2013 

 

 77,571 

 

 

 3,947 

 

 

 27,258 

 

 

 - 

 

 

 26,781 

 

 

 81,995 

 

2012 

 

 83,475 

 

 

 2,080 

 

 

 27,084 

 

 

 - 

 

 

 35,068 

 

 

 77,571 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NSTAR Electric:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reserves Deducted from Assets -

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reserves for Uncollectible Accounts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014 

$

 41,679 

 

$

 24,740 

 

$

 627 

 

$

 - 

 

$

 26,376 

 

$

 40,670 

 

2013 

 

 44,115 

 

 

 28,108 

 

 

 - 

 

 

 - 

 

 

 30,544 

 

 

 41,679 

 

2012 

 

 27,118 

 

 

 40,301 

 

 

 - 

 

 

 - 

 

 

 23,304 

 

 

 44,115 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

PSNH:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reserves Deducted from Assets -

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reserves for Uncollectible Accounts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014 

$

 7,364 

 

$

 6,815 

 

$

 797 

 

$

 - 

 

$

 7,313 

 

$

 7,663 

 

2013 

 

 6,760 

 

 

 6,608 

 

 

 779 

 

 

 - 

 

 

 6,783 

 

 

 7,364 

 

2012 

 

 7,190 

 

 

 6,457 

 

 

 2,481 

 

 

 - 

 

 

 9,368 

 

 

 6,760 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

WMECO:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reserves Deducted from Assets -

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reserves for Uncollectible Accounts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014 

$

 9,984 

 

$

 2,415 

 

$

 3,608 

 

$

 - 

 

$

 6,127 

 

$

 9,880 

 

2013 

 

 8,501 

 

 

 2,580 

 

 

 4,299 

 

 

 - 

 

 

 5,396 

 

 

 9,984 

 

2012 

 

 10,018 

 

 

 2,294 

 

 

 2,428 

 

 

 - 

 

 

 6,239 

 

 

 8,501 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

Amounts relate to uncollectible accounts receivables reserved for that are not charged to bad debt expense.  The PURA allows CL&P and Yankee Gas to accelerate the recovery of uncollectible hardship accounts receivables outstanding for greater than 90 days.  The DPU allows WMECO to recover in rates amounts associated with certain uncollectible hardship accounts receivables.  

(b)

Amounts written off, net of recoveries.  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 



S-4




EXHIBIT INDEX


Each document described below is incorporated by reference by the registrant(s) listed to the files identified, unless designated with a (*), which exhibits are filed herewith.  Management contracts and compensation plans or arrangements are designated with a (+).


Exhibit

Number

Description


3.

Articles of Incorporation and By-Laws


(A)

Northeast Utilities


3.1

Declaration of Trust of NU, as amended through May 10, 2005 (Exhibit A.1, NU Form U-1 filed June 23, 2005, File No. 70-10315)


(B)

The Connecticut Light and Power Company


3.1

Certificate of Incorporation of CL&P, restated to March 22, 1994 (Exhibit 3.2.1, 1993 CL&P Form 10-K, File No. 000-00404)


3.1.1

Certificate of Amendment to Certificate of Incorporation of CL&P, dated December 26, 1996 (Exhibit 3.2.2, 1996 CL&P Form 10-K filed March 25, 1997, File No. 001-11419)


3.1.2

Certificate of Amendment to Certificate of Incorporation of CL&P, dated April 27, 1998 (Exhibit 3.2.3, 1998 CL&P Form 10-K filed March 23, 1999, File No. 000-00404)


3.1.3

Amended and Restated Certificate of Incorporation of CL&P, dated effective January 3, 2012 (Exhibit 3(i), CL&P Current Report on Form 8-K filed January 9, 2012, File No. 000-00404)


3.2

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


(C)

NSTAR Electric Company


3.1

Restated Articles of Organization of NSTAR Electric Company, fka Boston Edison Company (Exhibit 3.1, NSTAR Electric Form 10-Q for the Quarter Ended June 30, 1994 filed August 12, 1994, File No. 001-02301)


3.2

Bylaws of NSTAR Electric Company, as amended and restated effective September 29, 2014 (Exhibit 3.1, NSTAR Electric Current Report on Form 8-K filed October 2, 2014, File No. 000-02301)


(D)

Public Service Company of New Hampshire


3.1

Articles of Incorporation, as amended to May 16, 1991 (Exhibit 3.3.1, 1993 PSNH Form 10-K filed March 25, 1994, File No. 001-06392)


3.2

By-laws of PSNH, as in effect June 27, 2008 (Exhibit 3, PSNH Form 10-Q for the Quarter Ended June 30, 2008 filed August 7, 2008, File No. 001-06392)


(E)

Western Massachusetts Electric Company


3.1

Articles of Organization of WMECO, restated to February 23, 1995 (Exhibit 3.4.1, 1994 WMECO Form 10-K filed March 27, 1995, File No. 001-07624)


3.2

By-laws of WMECO, as amended to April 1, 1999 (Exhibit 3.1, WMECO Form 10-Q for the Quarter Ended June 30, 1999 filed August 13, 1999, File No. 000-07624)


3.2.1

By-laws of WMECO, as further amended to May 1, 2000 (Exhibit 3.1, WMECO Form 10-Q for the Quarter Ended June 30, 2000 filed August 11, 2000, File No. 000-07624)




E-1




4.

Instruments defining the rights of security holders, including indentures


(A)

Northeast Utilities


4.1

Indenture between NU and The Bank of New York as Trustee dated as of April 1, 2002 (Exhibit A-3, NU 35-CERT filed April 16, 2002, File No. 070-09535)


4.1.1

Fifth Supplemental Indenture between NU and The Bank of New York Trust Company N.A., as Trustee, dated as of May 1, 2013, relating to $300 million of Senior Notes, Series E, due 2018 and $400 million of Senior Notes, Series F, due 2023 (Exhibit 4.1, NU Current Report on Form 8-K filed May 16, 2013, File No. 001-05324)


4.1.2

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


4.2

Indenture dated as of January 12, 2000, between NU, as successor to NSTAR LLC, as successor to NSTAR, and Bank One Trust Company N.A. (Exhibit 4.1 to NSTAR Registration Statement on Form S-3, File No. 333-94735)


4.2.1

Form of 4.50% Debenture Due 2019 (Exhibit 99.2, NSTAR Form 8-K filed November 16, 2009, File No. 001-14768)


4.3

Credit Agreement, dated July 25, 2012, by and among NU, CL&P, NSTAR Gas, NSTAR LLC, PSNH, WMECO, Yankee Gas Services Company and the Banks named therein, pursuant to which Bank of America, N.A. serves as Administrative Agent (Exhibit 4.1, NU Form 10-Q for the Quarter Ended September 30, 2012, filed November 7, 2012, File No. 001-05324)


4.3.1

First Amendment to Credit Agreement, dated September 6, 2013, by and among NU, CL&P, NSTAR Gas, NSTAR LLC, PSNH, WMECO, Yankee Gas Services Company and the Banks named therein, pursuant to which Bank of America, N.A. serves as Administrative Agent (Exhibit 4.1, NU Current Report on Form 8-K filed September 12, 2013, File No. 001-05324)


(B)

The Connecticut Light and Power Company


4.1

Indenture of Mortgage and Deed of Trust between CL&P and Bankers Trust Company, Trustee, dated as of May 1, 1921 (Composite including all twenty-four amendments to May 1, 1967) (Exhibit 4.1.1, 1989 NU Form 10-K, File No. 001-05324)


4.1.1

Series D Supplemental Indentures to the Composite May 1, 1921 Indenture of Mortgage and Deed of Trust between CL&P and Bankers Trust Company, dated as of October 1, 1994 (Exhibit 4.2.16, 1994 CL&P Form 10-K filed March 27, 1995, File No. 001-11419)


4.1.2

Series A Supplemental Indenture between CL&P and Deutsche Bank Trust Company Americas, as Trustee, dated as of September 1, 2004 (Exhibit 99.2, CL&P Current Report on Form 8-K filed September 22, 2004, File No. 000-00404)


4.1.3

Series B Supplemental Indenture between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of September 1, 2004 (Exhibit 99.5, CL&P Current Report on Form 8-K filed September 22, 2004, File No. 000-00404)


4.2

Composite Indenture of Mortgage and Deed of Trust between CL&P and Deutsche Bank Trust Company Americas f/k/a Bankers Trust Company, dated as of May 1, 1921, as amended and supplemented by seventy-three supplemental mortgages to and including Supplemental Mortgage dated as of April 1, 2005 (Exhibit 99.5, CL&P Current Report on Form 8-K filed April 13, 2005, File No. 000-00404)


4.2.1

Supplemental Indenture (2005 Series A Bonds and 2005 Series B Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of April 1, 2005 (Exhibit 99.2, CL&P Current Report on Form 8-K filed April 13, 2005, File No. 000-00404)


4.2.2

Supplemental Indenture (2007 Series A Bonds and 2007 Series B Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of March 1, 2007 (Exhibit 99.2, CL&P Current Report on Form 8-K filed March 29, 2007, File No. 000-00404)


4.2.3

Supplemental Indenture (2007 Series C Bonds and 2007 Series D Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of September 1, 2007 (Exhibit 4, CL&P Current Report on Form 8-K filed September 19, 2007, File No. 000-00404)


4.2.4

Supplemental Indenture (2008 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of May 1, 2008 (Exhibit 4, CL&P Current Report on Form 8-K filed May 29, 2008, File No. 000-00404)




E-2




4.2.5

Supplemental Indenture (2009 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of February 1, 2009 (Exhibit 4, CL&P Current Report on Form 8-K filed February 19, 2009, File No. 000-00404)


4.2.6

Supplemental Indenture (2011 Series A and Series B Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of October 1, 2011 (Exhibit 4.1, CL&P Current Report on Form 8-K filed October 28, 2011, File No. 000-00404)


4.2.7

Supplemental Indenture (2013 Series A Bond) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of January 1, 2013 (Exhibit 4.1, CL&P Current Report on Form 8-K filed January 22, 2013, File No. 000-00404)


4.2.8

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)


4.3

Amended and Restated Loan Agreement between Connecticut Development Authority and CL&P dated as of May 1, 1996 and Amended and Restated as of January 1, 1997 (Pollution Control Revenue Bond - 1996A Series) (Exhibit 4.2.24, 1996 CL&P Form 10-K filed March 25, 1997, File No. 001-11419)


4.3.1

First Amendment to Amended and Restated Loan Agreement, between the Connecticut Development Authority and CL&P dated as of October 1, 2008 (Pollution Control Revenue Bond-1996A Series) (Exhibit 10.1, CL&P Form 10-Q for the Quarter Ended September 30, 2008, filed November 10, 2008, File No. 000-00404)


4.4

Amended and Restated Indenture of Trust between Connecticut Development Authority and Fleet National Bank, the Trustee dated as of May 1, 1996 and Amended and Restated as of January 1, 1997 (Pollution Control Revenue Bond-1996A Series) (Exhibit 4.2.24.1, 1996 CL&P Form 10-K, filed March 25, 1997, File No. 001-11419)


4.4.1

First Amendment to Amended and Restated Indenture of Trust between Connecticut Development Authority and U.S. Bank National Association, as Trustee dated as of October 1, 2008 (Exhibit 10.2 CL&P Form 10-Q for the Quarter Ended September 30, 2008, filed November 10, 2008, File No. 000-00404)


4.5

Loan Agreement between Connecticut Development Authority and CL&P (Pollution Control Revenue Refunding Bonds – 2011A Series) dated as of October 1, 2011 (Exhibit 1.1, CL&P Current Report on Form 8-K filed October 28, 2011, File No. 000-00404)


4.6

Credit Agreement, dated July 25, 2012, by and among NU, CL&P, NSTAR Gas, NSTAR LLC, PSNH, WMECO, Yankee Gas Services Company and the Banks named therein, pursuant to which Bank of America, N.A. serves as Administrative Agent (Exhibit 4.1, CL&P Form 10-Q for the Quarter Ended September 30, 2012, filed November 7, 2012, File No. 001-05324)


4.6.1

First Amendment to Credit Agreement, dated September 6, 2013, by and among NU, CL&P, NSTAR Gas, NSTAR LLC, PSNH, WMECO, Yankee Gas Services Company and the Banks named therein, pursuant to which Bank of America, N.A. serves as Administrative Agent (Exhibit 4.1, CL&P Current Report on Form 8-K filed on September 12, 2013, File No. 001-05324)


(C)

NSTAR Electric Company


4.1

Indenture between Boston Edison Company and the Bank of New York (as successor to Bank of Montreal Trust Company) (Exhibit 4.1, NSTAR Electric Form 10-Q for the Quarter Ended September 30, 1988, File No. 001-02301)


4.1.1

A Form of 5.75% Debenture Due March 15, 2036 (Exhibit 99.2, Boston Edison Company Current  Report on Form 8-K filed March 17, 2006, File No. 001-02301)


4.1.2

A Form of 5.625% Debenture Due November 15, 2017 (Exhibit 99.2, NSTAR Electric Company Current Report on Form 8-K filed November 20, 2007 and filed February 17, 2009, File No. 001-02301)


4.1.3

A Form of 5.50% Debenture Due March 15, 2040 (Exhibit 99.2, NSTAR Electric Company Current Report on Form 8-K filed March 15, 2010, File No. 001-02301)


4.1.4

A Form of 2.375% Debenture Due 2022 (Exhibit 4, NSTAR Electric Company Current Report on Form 8-K filed October 18, 2012, File No. 001-02301)


4.1.5

A Form of Floating Rate Debenture Due 2016 (Exhibit 4, NSTAR Electric Company Current Report on Form 8-K filed May 22, 2013, File No. 001-02301)


4.1.6

A Form of 4.40% Debenture Due 2044 (Exhibit 4, NSTAR Electric Company Current Report on Form 8-K filed March 13, 2014, File No. 001-02301)



E-3





4.2

Credit Agreement, dated July 25, 2012, by and between NSTAR Electric and the Banks named therein, pursuant to which Barclays Bank PLC serves as Administrative Agent and Swing Line Lender (Exhibit 4.1, NSTAR Electric Company Form 10-Q for the Quarter Ended September 30, 2012, filed November 7, 2012, File No. 001-05324)


4.2.1

First Amendment to Credit Agreement, dated September 6, 2013, by and among NU, CL&P, NSTAR Gas, NSTAR LLC, PSNH, WMECO, Yankee Gas Services Company and the Banks named therein, pursuant to which Bank of America, N.A. serves as Administrative Agent (Exhibit 4.1, NSTAR Electric Company Current Report on Form 8-K filed on September 12, 2013, File No. 001-05324)


(D)

Public Service Company of New Hampshire


4.1

First Mortgage Indenture between PSNH and First Fidelity Bank, National Association, New Jersey, now First Union National Bank, Trustee, dated as of August 15, 1978 (Composite including all amendments effective June 1, 2011) (included as Exhibit C to the Eighteenth Supplemental Indenture filed as Exhibit 4.1 to PSNH Current Report on Form 8-K filed June 2, 2011, File No. 001-06392)


4.1.1

Fourteenth Supplemental Indenture between PSNH and Wachovia Bank, National Association successor to First Union National Bank, as successor to First Fidelity Bank, National Association, as Trustee dated as of October 1, 2005 (Exhibit 99.2, PSNH Current Report on Form 8-K filed October 6, 2005, File No. 001-06392)


4.1.2

Fifteenth Supplemental Indenture between PSNH and Wachovia Bank, National Association successor to First Union National Bank, as successor to First Fidelity Bank, National Association, as Trustee dated as of September 1, 2007 (Exhibit 4.1, PSNH Current Report on Form 8-K filed September 25, 2007, File No. 001-06392)


4.1.3

Sixteenth Supplemental Indenture between PSNH and U.S. Bank National Association, Trustee, dated as of May 1, 2008 (Exhibit 4.1 to PSNH Current Report on Form 8-K filed May 29, 2008 (File No.001-06392)


4.1.4

Seventeenth Supplemental Indenture, between PSNH and U.S. Bank National Association, as Trustee dated as of December 1, 2009 (Exhibit 4.1, PSNH Current Report on Form 8-K filed December 15, 2009 (File No. 001-06392)


4.1.5

Eighteenth Supplemental Indenture, between PSNH and U.S. Bank National Association, as Trustee dated as of May 1, 2011 (Exhibit 4.1, PSNH Current Report on Form 8-K filed June 2, 2011 (File No. 001-06392)


4.1.6

Nineteenth Supplemental Indenture, between PSNH and U.S. Bank National Association, as Trustee dated as of September 1, 2011 (Exhibit 4.1, PSNH Current Report on Form 8-K filed September 16, 2011 (File No. 001-06392)


4.1.7

Twentieth Supplemental Indenture, between PSNH and U.S. Bank National Association, as Trustee dated as of November 1, 2013 (Exhibit 4.1, PSNH Current Report on Form 8-K filed November 20, 2013 (File No. 001-06392)


4.1.8

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)


4.2

Series A Loan and Trust Agreement among Business Finance Authority of the State of New Hampshire and PSNH and State Street Bank and Trust Company, as Trustee (Tax Exempt Pollution Control Bonds) dated as of October 1, 2001 (Exhibit 4.3.4, 2001 NU Form 10-K filed March 22, 2002, File No. 001-05324)


4.3

Credit Agreement, dated July 25, 2012, by and among NU, CL&P, NSTAR Gas, NSTAR LLC, PSNH, WMECO, Yankee Gas Services Company and the Banks named therein, pursuant to which Bank of America, N.A. serves as Administrative Agent  (Exhibit 4.1, PSNH Form 10-Q for the Quarter Ended September 30, 2012, filed November 7, 2012, File No. 001-05324)


4.3.1

First Amendment to Credit Agreement, dated September 6, 2013, by and among NU, CL&P, NSTAR Gas, NSTAR LLC, PSNH, WMECO, Yankee Gas Services Company and the Banks named therein, pursuant to which Bank of America, N.A. serves as Administrative Agent (Exhibit 4.1, PSNH Current Report on Form 8-K filed on September 12, 2013, File No. 001-05324)


(E)

Western Massachusetts Electric Company


4.1

Loan Agreement between Connecticut Development Authority and WMECO, (Pollution Control Revenue Bonds - Series A, Tax Exempt Refunding) dated as of September 1, 1993 (Exhibit 4.4.13, 1993 WMECO Form 10-K filed March 25,1994, File No. 000-07624)


4.2

Indenture between WMECO and The Bank of New York, as Trustee, dated as of September 1, 2003 (Exhibit 99.2, WMECO Current Report on Form 8-K filed October 8, 2003, File No. 000-07624)


4.2.1

Second Supplemental Indenture between WMECO and The Bank of New York, as Trustee dated as of September 1, 2004 (Exhibit 4.1, WMECO Current Report on Form 8-K filed September 27, 2004, File No. 000-07624)



E-4





4.2.2

Third Supplemental Indenture between WMECO and The Bank of New York Trust, as Trustee, dated as of August 1, 2005 (Exhibit 4.1, WMECO Current Report on Form 8-K filed August 12, 2005, File No. 000-07624)


4.2.3

Fourth Supplemental Indenture between WMECO and The Bank of New York Trust, as Trustee, dated as of August 1, 2007 (Exhibit 4.1, WMECO Current Report on Form 8-K filed August 20, 2007, File No. 000-07624)


4.2.4

Fifth Supplemental Indenture between WMECO and The Bank of New York Trust Company, N.A., as Trustee, dated as of March 1, 2010 (Exhibit 4.1, WMECO Current Report on Form 8-K filed March 10, 2010, File No. 000-07624)


4.2.5

Sixth Supplemental Indenture between WMECO and The Bank of New York Trust Company, N.A., as Trustee, dated as of September 15, 2011 (Exhibit 4.1, WMECO Current Report on Form 8-K filed September 19, 2011, File No. 000-07624)


4.2.6

Seventh Supplemental Indenture between WMECO and The Bank of New York Trust Company, N.A., as Trustee, dated as of November 1, 2013 (Exhibit 4.1, WMECO Current Report on Form 8-K filed November 21, 2013, File No. 000-07624)


4.3

Credit Agreement, dated July 25, 2012, by and among NU, CL&P, NSTAR Gas, NSTAR LLC, PSNH, WMECO, Yankee Gas Services Company and the Banks named therein, pursuant to which Bank of America, N.A. serves as Administrative Agent  (Exhibit 4.1, WMECO Form 10-Q for the Quarter Ended September 30, 2012, filed November 7, 2012, File No. 001-05324)


4.3.1

First Amendment to Credit Agreement, dated September 6, 2013, by and among NU, CL&P, NSTAR Gas, NSTAR LLC, PSNH, WMECO, Yankee Gas Services Company and the Banks named therein, pursuant to which Bank of America, N.A. serves as Administrative Agent  Exhibit 4.1, WMECO Current Report on Form 8-K filed on September 12, 2013, File No. 001-05324)


10.

Material Contracts


(A)

NU


10.1

Lease between The Rocky River Realty Company and Northeast Utilities Service Company dated as of April 14, 1992 with respect to the Berlin, Connecticut headquarters (Exhibit 10.29.1, 1992 NU Form 10-K, File No. 001-05324)


10.2

Amended and Restated Indenture of Mortgage and Deed of Trust between Yankee Gas Services Company and the Bank of New York Mellon Trust company, N.A. formerly Connecticut National Bank, as Trustee, dated July 1, 1989, (Composite including all amendments effective January 1, 2014) (included as Exhibit B to the Eleventh Supplemental Indenture filed as Exhibit 10, NU Form 10-Q for the Quarter Ended March 31, 2014 filed May 2, 2014, File No. 001-05324)


10.2.1

First Supplemental Indenture of Mortgage and Deed of Trust between Yankee Gas Services Company and The Connecticut National Bank, as Trustee, dated April 1, 1992 (Yankee Energy System, Inc. Registration Statement on Form S-3, dated October 2, 1992, File No. 33-52750


10.2.2

Sixth Supplemental Indenture of Mortgage and Deed of Trust between Yankee Gas Services Company and The Bank of New York, as Successor Trustee to Fleet Bank (formerly The Connecticut National Bank) dated January 1, 2004 (Exhibit 10.5.6, 2004 NU Form 10-K filed March 17, 2005, File No. 001-05324)


10.2.3

Seventh Supplemental Indenture of Mortgage and Deed of Trust between Yankee Gas Services Company and The Bank of New York, as Successor Trustee to Fleet Bank (formerly The Connecticut National Bank) dated November 1, 2004 (Exhibit 10.5.7, 2004 NU Form 10-K filed March 17, 2005, File No. 001-05324)


10.2.4

Eighth Supplemental Indenture of Mortgage and Deed of Trust between Yankee Gas Services Company and The Bank of New York, as Successor Trustee to Fleet Bank (formerly the Connecticut National Bank) dated July 1, 2005 (Exhibit 10.5.8, NU Form 10-Q for the Quarter Ended June 30, 2005 filed August 8, 2005, File No. 001-05324)


10.2.5

Ninth Supplemental Indenture of Mortgage and Deed of Trust between Yankee Gas Services Company and The Bank of New York Mellon Trust Company, N.A., successor as Trustee to The Bank of New York, as successor to Fleet National Bank (formerly known as The Connecticut National Bank) dated as of October 1, 2008 (Exhibit 10-1, NU Form 10-Q for the Quarter Ended September 30, 2008 filed November 10, 2008, File No. 001-05324)


10.2.6

Tenth Supplemental Indenture of Mortgage and Deed of Trust between Yankee Gas Services Company and The Bank of New York Mellon Trust Company, N.A., successor as Trustee to The Bank of New York, as successor to Fleet National Bank (formerly known as The Connecticut National Bank), dated as of April 1, 2010 (Exhibit 10, NU Form 10-Q for the Quarter Ended March 31, 2010 filed May 7, 2010, File No. 001-05324)




E-5




10.2.7

Eleventh Supplemental Indenture of Mortgage and Deed of Trust between Yankee Gas Services Company and The Bank of New York Mellon Trust Company, N.A., successor as Trustee to The Bank of New York, as successor to Fleet National Bank (formerly known as The Connecticut National Bank), dated as of January 1, 2014 (Exhibit 10, NU Form 10-Q for the Quarter Ended March 31, 2014 filed May 2, 2014, File No. 001-05324)


* +10.3

Northeast Utilities Board of Trustees' Compensation Arrangement Summary


+10.4

Amended and Restated Northeast Utilities Deferred Compensation Plan for Trustees, effective January 1, 2009 (Exhibit  10.6, NU Form 10-Q for the Quarter Ended September 30, 2008 filed November 10, 2008, File No. 001-05324)


 10.5

Composite Transmission Service Agreement, by and between Northern Pass Transmission LLC, as Owner and H.Q. Hydro Renewable Energy, Inc., as Purchaser dated October 4, 2010 and effective February 14, 2014


(B)

NU, CL&P, PSNH and WMECO


 10.1

Amended and Restated Form of Service Contract between each of NU, CL&P and WMECO and Northeast Utilities Service Company (NUSCO) dated as of January 1, 2014. (Exhibit 10.1, NU Form 10-K filed on February 25, 2014, File No. 001-05324)


10.2

Agreements among New England Utilities with respect to the Hydro-Quebec interconnection projects (Exhibits 10(u) and 10(v); 10(w), 10(x), and 10(y), 1990 and 1988, respectively, Form 10-K of New England Electric System, File No. 001-03446)


10.3

Transmission Operating Agreement between the Initial Participating Transmission Owners, Additional Participating Transmission Owners and ISO New England, Inc. dated as of February 1, 2005 (Exhibit 10.29, 2004 NU Form 10-K filed March 17, 2005, File No. 001-05324)


10.3.1

Rate Design and Funds Disbursement Agreement among the Initial Participating Transmission Owners, Additional Participating Transmission Owners and ISO New England, Inc., effective June 30, 2006 (Exhibit 10.22.1, 2006 NU Form 10-K filed March 1, 2007, File No. 001-05324)


10.4

Northeast Utilities Service Company Transmission and Ancillary Service Wholesale Revenue Allocation Methodology among The Connecticut Light and Power Company, Western Massachusetts Electric Company, Public Service Company of New Hampshire, Holyoke Water Power Company and Holyoke Power and Electric Company Trustee dated as of January 1, 2008 (Exhibit 10.1, NU Form 10-Q for the Quarter Ended March 31, 2008 filed May 9, 2008, File No. 001-05324)


+10.5

Amended and Restated Employment Agreement with Gregory B. Butler, effective January 1, 2009 (Exhibit 10.7, 2008 NU Form 10-K filed February 27, 2009, File No. 001-05324)


+10.6

Amended and Restated Employment Agreement with David R. McHale, effective January 1, 2009 (Exhibit 10.8, 2008 NU Form 10-K filed February 27, 2009, File No. 001-05324)


+10.7

Amended and Restated Memorandum Agreement between Northeast Utilities and Leon J. Olivier effective January 1, 2009 (Exhibit 10.9, 2008 NU Form 10-K filed February 27, 2009, File No. 001-05324)


+10.8

Amended and Restated Incentive Plan Effective January 1, 2009 (Exhibit 10.3, NU Form 10-Q for the Quarter Ended September 30, 2008 filed November 10, 2008, File No. 001-05324)


+10.9

Amended and Restated Supplemental Executive Retirement Plan for Officers of Northeast Utilities System Company effective January 1, 2009 (Exhibit 10.5, NU Form 10-Q for the Quarter Ended September 30, 2008 filed November 10, 2008, File No. 001-05324)


+10.10

Trust under Supplemental Executive Retirement Plan dated May 2, 1994 (Exhibit 10.33, 2002 NU Form 10-K filed March 21, 2003, File No. 001-05324)


 +10.10.1

First Amendment to Trust Under Supplemental Executive Retirement Plan, effective as of December 10, 2002 (Exhibit 10 (B) 10.19.1, 2003 NU Form 10-K filed March 12, 2004, File No. 001-05324)


 +10.10.2

Second Amendment to Trust Under Supplemental Executive Retirement Plan , effective as of November 12, 2008 (Exhibit 10.12.2, 2008 NU Form 10-K filed February 27, 2009, File No. 001-05324)


+10.11

Special Severance Program for Officers of NU System Companies as of January 1, 2009 (Exhibit 10.2, NU Form 10-Q for the Quarter Ended September 30, 2008 filed November 10, 2008, File No. 001-05324)


+10.12

Amended and Restated Northeast Utilities Deferred Compensation Plan for Executives effective as of January 1, 2009 (Exhibit 10.4 NU Form 10-Q for Quarter Ended September 30, 2008 filed November 10, 2008, File No. 001-05324)


+10.13

Northeast Utilities Retention Agreement (Exhibit 10.1, NU Registration Statement on Form S-4, filed November 22, 2010, File No. 333-170754)



E-6





10.14

Northeast Utilities System's Third Amended and Restated Tax Allocation Agreement dated as of April 10, 2012, (Exhibit 10.1 NU Form 10-Q for Quarter Ended June 30, 2012 filed August 7, 2012, File No. 001-05324)


(C)

NU and CL&P


10.1

CL&P Agreement Re: Connecticut NEEWS Projects by and between CL&P and The United Illuminating Company dated July 14, 2010 (Exhibit 10, CL&P Form 10-Q for the Quarter Ended June 30, 2010 filed August 6, 2010, File No. 000-00404)


(D)

NU and NSTAR Electric


10.1

NSTAR Electric Company Restructuring Settlement Agreement dated July 1997, (Exhibit  10.12, Boston Edison 1997 Form 10-K filed March 30, 1998, File No. 001-02301)


10.2

Amended and Restated Power Purchase Agreement (NEA A PPA), dated August 19, 2004, by and between Boston Edison and Northeast Energy Associates L.P. (Exhibit 10.18, 2005 NSTAR Form 10-K filed February 21, 2006, File No. 001-14768)


10.3

Amended and Restated Power Purchase Agreement (NEA B PPA), dated August 19, 2004, by and between ComElectric and Northeast Energy Associates L. P. (Exhibit 10.19,  2005 NSTAR Form 10-K filed February 21, 2006, File No. 001-14768)


10.4

Amended and Restated Power Purchase Agreement (CECO 1 PPA), dated August 19, 2004 by and between ComElectric and Northeast Energy Associates L. P. (Exhibit 10.20, 2005 NSTAR Form 10-K filed February 21, 2006, File No. 001-14768)


10.5

Amended and Restated Power Purchase Agreement (CECO 2 PPA), dated August 19, 2004 by and between ComElectric and Northeast Energy Associates L. P. (Exhibit 10.21, 2005 NSTAR Form 10-K filed February 21, 2006, File No. 001-14768)


10.6

The Bellingham Execution Agreement, dated August 19, 2004 between Boston Edison, ComElectric and Northeast Energy Associates L. P. (Exhibit 10.22, 2005 NSTAR Form 10-K filed February 21, 2006, File No. 001-14768)


10.7

Second Restated NEPOOL Agreement among NSTAR Electric and various other electric utilities operating in New England, dated August 16, 2004 (Exhibit 10.2.1.1, 2005 NSTAR Form 10-K filed February 21, 2006, File No. 001-14768)


10.8

Transmission Operating Agreement among NSTAR Electric and various electric transmission providers in New England and ISO New England Inc., dated February 1, 2005 (Exhibit 10.2.1.2, 2005 NSTAR Form 10-K filed February 21, 2006, File No. 001-14768)


10.9

Market Participants Service Agreement among NSTAR Electric and various other electric utilities operating in New England, NEPOOL and ISO New England Inc., dated February 1, 2005 (Exhibit 10.2.1.3, 2005 NSTAR Form 10-K filed February 21, 2006, File No. 001-14768)


10.10

Rate Design and Funds Disbursement Agreement among NSTAR Electric and various other electric transmission providers in New England, dated February 1, 2005 (Exhibit 10.2.1.4, 2005 NSTAR Form 10-K filed February 21, 2006, File No. 001-14768)


10.11

Participants Agreement among NSTAR Electric, various electric utilities operating in New England, NEPOOL and ISO-New England, Inc., dated February 1, 2005 (Exhibit 10.2.1.4, 2006 NSTAR Form 10-K filed February 16, 2007, File No. 001-14768)


+10.12

NSTAR Excess Benefit Plan, effective August  25, 1999 (Exhibit 10.1 1999 NSTAR Form 10-K/A filed September 29, 2000, File No. 001-14768)


+10.12.1

NSTAR Excess Benefit Plan, incorporating the NSTAR 409A Excess Benefit Plan, as amended and restated effective January 1, 2008, dated December 24, 2008 (Exhibit 10.1.1 2008 NSTAR Form 10-K filed February 9, 2009, File No. 001-14768)


+10.13

NSTAR Supplemental Executive Retirement Plan, effective August 25, 1999 (Exhibit 10.2,1999 NSTAR Form 10-K/A filed September 29, 2000, File No. 001-14768)


+10.13.1

NSTAR Supplemental Executive Retirement Plan, incorporating the NSTAR 409A Supplemental Executive Retirement Plan, as amended and restated effective January 1, 2008, dated December 24, 2008 (Exhibit 10.2.1, 2008 NSTAR Form 10-K filed February 9, 2009, File No. 001-14768)


+10.14

Special Supplemental Executive Retirement Agreement between Boston Edison Company and Thomas J. May dated March 13, 1999, regarding Key Executive Benefit Plan and Supplemental Executive Retirement Plan (Exhibit 10.3, 1999 NSTAR Form 10-K/A filed September 9, 2000, File No. 001-14768)


+10.15

Amended and Restated Change in Control Agreement by and between NSTAR and Thomas J. May dated November 15, 2007 (Exhibit 10.5, 2007 NSTAR Form 10-K filed February 11, 2008, File No. 001-14768)




E-7




+10.16

NSTAR Deferred Compensation Plan, (Restated Effective August 25, 1999) (Exhibit 10.10, 1999 NSTAR Form 10-K/A filed September 29, 2000, File No. 001-14768)


+10.16.1

NSTAR Deferred Compensation Plan, incorporating the NSTAR 409A Deferred Compensation Plan, as amended and restated effective January 1, 2008, dated December 24, 2008 (Exhibit 10.6.1, 2008 NSTAR Form 10-K filed February 9, 2009, File No. 001-14768)


+10.17

NSTAR 2007 Long Term Incentive Plan, effective May 3, 2007 (Exhibit 10.2, NU Registration Statement on Form S-8 filed on May 8, 2012)


+10.17.1

Deferred Common Share/Dividend Equivalent Award, Stock Option Grant, Option Certificate and Performance Share Award/Dividend Equivalent Award Agreement Under the NSTAR 2007 Long Term Incentive Plan, by and between NSTAR and Thomas J. May, dated January 24, 2008 (Exhibit 10.8.1, 2007 NSTAR Form 10-K filed February 11, 2008, File No. 001-14768)


+10.17.2

Deferred Common Share/Dividend Equivalent Award, Stock Option Grant, Option Certificate and Performance Share Award/Dividend Equivalent Award Agreement Under the NSTAR 2007 Long Term Incentive Plan, by and between NSTAR and James J. Judge, dated January 24, 2008 (Exhibit 10.8.2, 2007 NSTAR Form 10-K filed February 11, 2008, File No. 001-14768)


+10.17.3

Deferred Common Share/Dividend Equivalent Award, Stock Option Grant, Option Certificate and Performance Share Award/Dividend Equivalent Award Agreement Under the NSTAR 2007 Long Term Incentive Plan by and between NSTAR and NSTAR’s other Senior Vice Presidents and Vice Presidents, dated January 24, 2008 (in form) (Exhibit 10.8.6, 2007 NSTAR Form 10-K filed February 11, 2008, File No. 001-14768)


+10.18

Amended and Restated Change in Control Agreement by and between James J. Judge and NSTAR, dated November 15, 2007 (Exhibit 10.9, 2007 NSTAR Form 10-K filed February 11, 2008, File No. 001-14768)


+10.19

NSTAR Trustees’ Deferred Plan (Restated Effective August 25, 1999), dated October 20, 2000 (Exhibit 10.4, NSTAR Form 10-Q for the quarter ended September 30, 2000 filed November 14, 2000, File No. 001-14768)


10.20.1

NSTAR Trustees’ Deferred Plan, incorporating the 409A Trustees’ Deferred Plan, effective January 1, 2008, dated December 24, 2008 (Exhibit 10.10.1, 2008 NSTAR Form 10-K filed February 9, 2009, File No. 001-14768)


+10.20

Master Trust Agreement between NSTAR and State Street Bank and Trust Company (Rabbi Trust), effective August 25, 1999 (Exhibit 10.5, NSTAR Form 10-Q for the Quarter Ended September 30, 2000 filed November 14, 2000, File No. 001-14768)


+10.21

Amended and Restated Change in Control Agreement by and between NSTAR’s other Senior Vice Presidents and NSTAR (in form), dated November 15, 2007 (Exhibit 10.15, 2007 NSTAR Form 10-K filed February 11, 2008, File No. 001-14768)


+10.22

Amended and Restated Change in Control Agreement between NSTAR’s Vice Presidents and NSTAR (in form), dated November 15, 2007 (Exhibit 10.16, 2007 NSTAR Form 10-K filed February 11, 2008, File No. 001-14768)


+10.23

Currently effective Change in Control Agreement between NSTAR’s Vice Presidents and NSTAR (in form) (Exhibit 10.17, 2009 NSTAR Form 10-K filed February 25, 2010, File No. 001-14768)


+10.24

Executive Retention Award Agreement, dated November 19, 2010, by and between NSTAR and James J. Judge (Exhibit 99.2, NSTAR Current Report on Form 8-K filed November 22, 2010, File No. 001-14768)


10.25

MDTE Order approving Rate Settlement Agreement dated December 31, 2005 (Exhibit 99.2, NSTAR Current Report on Form 8-K filed January 4, 2006, File No. 001-14768)


(E)

NU and WMECO


10.1

Lease and Agreement by and between WMECO and Bank of New England, N.A., with BNE Realty Leasing Corporation of North Carolina dated as of December 15, 1988 (Exhibit 10.63, 1988 NU Form 10-K, File No. 001-05324)




E-8




*12.

Ratio of Earnings to Fixed Charges


(A)

Northeast Utilities


(B)

The Connecticut Light and Power Company


(C)

NSTAR Electric Company


(D)

Public Service Company of New Hampshire


(E)

Western Massachusetts Electric Company


*21.

Subsidiaries of the Registrant


*23.

Consents of Independent Registered Public Accounting Firm


*31.

Rule 13a – 14(a)/15 d – 14(a) Certifications


(A)

Northeast Utilities


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 February 25, 2015


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 February 25, 2015


(B)

The Connecticut Light and Power Company


31

Certification of Thomas J. May, Chairman 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 February 25, 2015


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 February 25, 2015


(C)

NSTAR Electric Company


31

Certification of Thomas J. May, Chairman of NSTAR Electric Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 25, 2015


31.1

Certification of James J. Judge, Executive Vice President and Chief Financial Officer of NSTAR Electric Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 25, 2015


(D)

Public Service Company of New Hampshire


31

Certification of Thomas J. May, Chairman 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 February 25, 2015


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 February 25, 2015


(E)

Western Massachusetts Electric Company


31

Certification of Thomas J. May, Chairman 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 February 25, 2015


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 February 25, 2015




E-9




*32

18 U.S.C. Section 1350 Certifications


(A)

Northeast Utilities


32

Certification of Thomas J. May, Chairman, President and Chief Executive Officer of Northeast Utilities and James J. Judge, Executive Vice President and Chief Financial Officer of Northeast Utilities, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated February 25, 2015


(B)

The Connecticut Light and Power Company


32

Certification of Thomas J. May, Chairman of The Connecticut Light and Power Company and James J. Judge, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated February 25, 2015


(C)

NSTAR Electric Company


32

Certification of Thomas J. May, Chairman of NSTAR Electric Company and James J. Judge, Executive Vice President and Chief Financial Officer of NSTAR Electric Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated February 25, 2015


(D)

Public Service Company of New Hampshire


32

Certification of Thomas J. May, Chairman of Public Service Company of New Hampshire and James J. Judge, Executive Vice President and Chief Financial Officer of Public Service Company of New Hampshire, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated February 25, 2015


(E)

Western Massachusetts Electric Company


32

Certification of Thomas J. May, Chairman of Western Massachusetts Electric Company and James J. Judge, Executive Vice President and Chief Financial Officer of Western Massachusetts Electric Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated February 25, 2015


*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




E-10