Northeast Utilities’ Five-Year Infrastructure Investment Plan Wall Street Access January 10, 2008

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Northeast Utilities’ Five-Year

Infrastructure Investment Plan

Wall Street Access

January 10, 2008

Lee Olivier, Executive Vice President – Operations

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Safe Harbor Provisions

This presentation contains statements concerning NU’s expectations, plans, objectives, future financial performance 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. In some cases, a listener can identify these forward-looking statements by words such as “estimate,” “expect,” “anticipate,” “intend,” “plan,” “believe,” “forecast,” “should,” “could,” and similar expressions. Forward-looking statements involve risks and uncertainties that may cause actual results or outcomes to differ materially from those included in the forward-looking statements. Factors that may cause actual results to differ materially from those included in the forward-looking statements include, but are not limited to, actions or inactions by local, state and federal regulatory bodies; competition and industry restructuring; changes in economic conditions; changes in weather patterns; changes in laws, regulations or regulatory policy; changes in levels or timing of capital expenditures; developments in legal or public policy doctrines; technological developments; changes in accounting standards and financial reporting regulations; fluctuations in the value of our remaining competitive electricity positions; actions of rating agencies; subsequent recognition, derecognition and measurement of tax positions; and other presently unknown or unforeseen factors. Other risk factors are detailed from time to time in our reports to the Securities and Exchange Commission. Any forward looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to update the information contained in any forward-looking statements to reflect developments or circumstances occurring after the statement is made.

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Today’s Discussion Topics

Key Initiatives

Regulated Investment Strategy

Transmission

New England’s Future Energy Challenges and Opportunities for NU

Generation

Distribution Rate Cases

Regulatory Updates

Emerging Challenges of Distribution Reliability

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Strong Execution of 2007 Strategy & Business Plan

Completed capital spend of $1.3 billion

All major infrastructure projects on schedule and on budget

Yankee Gas LNG facility in service and in rates

Achieved PSNH and Yankee Gas rate settlements

Successful completion of NERC compliance audit

Consolidated system reliability target met

Advancing future initiatives

Northern New England, Canada transmission concept projects

Connecticut: Automated Meter Infrastructure; Integrated Resource Plan; Peaking Generation Proposal

Major projects delivering significant value for customers

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Key Signposts For Our Continued Success

Continue to successfully execute

Effectively deploy the capital in the five-year plan

Manage the regulatory business model to earn on the capital

Develop and deliver solutions for the region’s energy challenges

Identify projects that have reliability, environmental and cost benefits for

customers

Transmission

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Transmission Capital Program and Rate Base Continue to Grow

2006 2007 2008 2009 2010 2011 2012

Fall 2005 EEI Conference

Today

Fall 2006 EEI Conference

Five-Year Capital Program -- $2.3 Billion



Annual Plant-in-Service: $ Millions

$391 $307 $724 $883 $341 $396 $617

(Actual) (Projected)

Operating Company

Actual

12/31/06

Rate Base

($ Millions)

Projected

12/31/12

Rate Base

($ Millions)

CL&P 841 2,864

WMECO 71 621

PSNH 134 459

Total NU 1,046 3,944

(Actual)

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Rate Base Composition

2006 Rate Base Composition

2012E Rate Base Composition

$4.5 billion

$9.4 billion

Rate Base: $1.05 billion (Actual 2006)

’07-’12 Capex: $3.8 billion





ElectricityTransmission

ElectricityDistribution & Generation

Gas LDC

Transmission becomes much larger share of total rate baseTransmission becomes much larger share of total rate base

23%

11%

66% Transmission

Gas

Dist. & Generation

42%

9%

49%

Transmission

Gas

Dist. & Generation

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2008-2012 Transmission Capital Expenditures

Increase By Over 20% From Previous Five-Year Program

$0

$100

$200

$300

$400

$500

$600

$700

$800

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Major Southwest CT NEEWS Springfield 115-kV Cables Other

Historic Forecast

In M

illio

ns

Up To $3.0 Billion $1,816 Million

$560 million of major SWCT

projects in 2008-2012 forecast

period; $1.68 billion in total

NEEWS projects estimated at

$1 billion during the 2008-2012 forecast

period

$1.1 billion of additional

forecasted projects

Successful completion of

SWCT projects

NEEWS projects ramping up

Springfield 115-kV Cables projects

estimated at $350 million during the

2008-2012 forecast period

Springfield 115-kV Cables project

ramping up

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Four Major Southwest Connecticut Transmission Projects –

A $1.68 Billion Investment, About 2/3 Complete

Bethel-Norwalk 345-kV underground& overhead$350 Million

21 miles 345-kV (56% underground)


Completed October 2006 at a cost of $335 million Middletown-Norwalk 345-kV

underground & overhead$1,047 Million (NU share)Glenbrook Cables

115-kV underground$223 Million

9 miles 115-kV underground

Projected in-service date: December 2008

Under contract – construction under way, 69% complete at 1/04/08

Long Island Cable138-kV cross-sound$72 Million (NU share)

11 miles 138-kV submarine cable

Joint project with LIPA

Projected in-service date: mid-2008

63% complete at 1/04/08



Joint project with United Illuminating

Projected in-service date: Second-half 2009

62% complete at 1/04/08

COMPLETE

50% of CT Load

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NEEWS and Springfield 115-kV Cables Projects Will Better

Connect Eastern, Western New England by 2013

Springfield 115-kV Cables Project

SPRINGFIELD

HARTFORD

345-kV Substation

Generation Station

345-kV ROW

115-kV ROW

Greater SpringfieldReliability Project

Central ConnecticutReliability Project

InterstateReliability Project

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Springfield 115-kV Cables & NEEWS Project Schedules

NEEWS

Springfield 115-kV Cables

Greater Springfield Reliability

(115-kV/345-kV)

Interstate Reliability (345-kV)

Central CT Reliability (345-kV)

ISO technical applications approval

December 2007 Mid 2008 Mid 2008 Late 2008

State siting application filed

December 2007 Mid 2008 Mid 2008 Late 2008

Procurement contracts

2008 - 2010 2009 – 2012 2009 – 2012 2010 - 2012

Siting completed Early 2009Late 2009/Early

2010Late 2009/Early

20102010

Construction targeted to start on staggered basis

2009 2010 20102010/Early

2011

In-service 2011 Late 2012/2013 Late 2012/2013 2013

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Other Forecast Projects Total $1.1 Billion

$1.1 Billion

CL&P

115-kV Reliability Program 30.0

Fiber Optic Communications 20.0

310/368 Line Split 29.0

Eastern Connecticut Reliability 190.5

Barbour Hill Autotransformer 10.7

Aging Equipment & NERC Compliance Upgrades (24% in RSP) 91.4

Numerous Projects Addressing Maintenance, Reliability & Load Growth (55% in RSP) 202.9

Total CL&P Other Projects 574.5

$'s Millions WMECO



Ludlow Transformer Repl. 12.0

Berkshire 2nd Autotransformer 9.9



Total WMECO Other Projects 134.9

$'s Millions PSNH



Scobie 3rd Autotransformer 12.4

White Mountain Region Upgrades 14.9

Monadnock Region Upgrades 26.6

Nashua Area Solution 14.0

Deerfield & Gosling Autos 52.7



Total PSNH Other Projects 401.3

$'s Millions

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Future Resources Aligned with Our Strategic Business Plans

Construction Expertise – experienced, proven firms, track record with NU Burns & McDonnell (Transmission, including NEEWS) Washington Group International (Merrimack Scrubber)

Labor – partnering with the largest U.S. transmission constructor Contract signed with Quanta for $750 million in transmission construction services Provides for 70% of labor over the next six years

Material – established worldwide network to procure key components Transformers, poles, underground cables and control systems

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Established Worldwide Access to Key Suppliers

GC Cable from Prysmian in Finland

GC DFR from Qualitrol in Ireland

GC Breakers & Switches from ABB Power in U.S.

GC Scada Cabinet from GE Harris in Canada

M-N Steel Poles from Thomas & Betts in U.S.

M-N Overhead Ground Wire from Intral in Canada

M-N 345-kV Breakers from HICO in South Korea

M-N Autotransformers & Transformers from Areva in Brazil

M-N Shunt Reactors from Siemens in Germany

M-N GIS from Mitsubishi in Japan

M-N 115-kV Cable from Prysmian in Italy

M-N 345-kV Cable from Silec in France

B-N Underground Cables from VISCAS in Japan

New England’s Future Energy

Challenges and Opportunities for NU

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Next Initiatives: Dealing With New England’s Emerging

Energy Challenges

Challenges andOpportunities

Dependence on natural gas

Highelectricity

costs

Regional Greenhouse Gas Initiative

(RGGI)requirements

IncreasingRenewable Portfolio

Standards(RPS)

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By 2020, a 17,000 GWh Gap Exists Between Existing Renewable

Resources And The Amount Required To Meet The RPS

Magnitude of meeting this challenge 2,500 MW of biomass (~$12 billion), or 6,600 MW of wind (~$8 billion), or 16,400 MW of solar (~$128 billion)

Magnitude of meeting this challenge 2,500 MW of biomass (~$12 billion), or 6,600 MW of wind (~$8 billion), or 16,400 MW of solar (~$128 billion)

CT: 27% by 2020

VT: 2005-2012 Load growth

to be met with renewables and capped at 10%.

ME: 40% by 2017

(currently 30%)

NH: 23.8% by 2025

RI: 16% by 2019

MA: 4% in 2009; 1% annual

increments thereafter

New England RPS Requirements

0%

5%

10%

15%

20%

25%

Year

% of

NE

Ener

gy

Requ

ireme

nts

RPS Requirements - % Existing Renewables - %

17,269 GWh

2020

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Meeting the Regional Greenhouse Gas Initiative (RGGI)

Requirements Will Be A Challenge

Magnitude of meeting this challenge for New England

31,400 GWh fossil generation replaced with low/no emissions resources

Equivalent to 4,500 MW of baseload generation (80% capacity factor)

Magnitude of meeting this challenge for New England

31,400 GWh fossil generation replaced with low/no emissions resources

Equivalent to 4,500 MW of baseload generation (80% capacity factor)

RGGI CO2 Emissions

40

60

80

100

120

140

160

180

200

220

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Year

Mill

ion

s o

f T

on

s

New England RGGI CO2 BudgetProjected New England CO2 Emissions10 State RGGI CapProjected 10 State CO2 Emissions

Projected New England CO2 Emissions @ 1.3% energy growth

New England RGGI Budget

10 State RGGI Cap

Projected 10 State CO2 Emissions (Source: Environment Northeast Business as Usual Scenario)

Projected CO2 Gaps: 10 State – 32 Million Tons New England – 18 Million Tons

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Northern New England and Eastern Canada Will

Become Valuable Sources to Meet New England’s Needs

H

N

W

Hydro

Nuclear

Wind

B Biomass

General Movement Of Power

New England’s Most Attractive Renewable Energy Locations

W

W

WW

W

B

B

B

B

N

H

H

H

QuebecHydro Quebec plans $20 Billion investment in Hydro and export transmission

Newfoundland & LabradorExploring development

of large Hydro facilities

New BrunswickExploring development

of 1 or 2 nuclear units

W

Eastern Canadian Development

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A Set of Complementary Projects with Tangible Benefits

for New England

HVDC Line from Hydro Quebec to central NH

HVDC Line from Hydro Quebec to central NH

HVDC Line Newington, NH to Boston Area

HVDC Line Newington, NH to Boston Area

Benefits A solution with real benefits for the region

Economic value CO2 reduction

Renewable resource additions Fuel diversity

HVDC tie line with Hydro Quebec allows for large import capability into New England

Optimizes use of existing and planned bulk power grid -- connects the DC tie line from Hydro Quebec at a good location on the New England AC system

Provides a new, strong and separate reliability path from HQ

Addition of north-south DC connection allows for enhanced power flows to southern New England load centers

Utilizes likely 345 kV upgrades in NH and VT to meet future reliability needs (in RSP today).

Utilizes likely 345 kV upgrades in NH and VT to meet future reliability needs (in RSP today).

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Regulated Generation & Distribution

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Regulated Generation Investments -- Merrimack Scrubber

Reduces 98% of sulfur emissions Reduces 85% of mercury emissions Avoids $15-20 million annually in sulfur credit purchases Impact on Merrimack production costs of no more than 0.6 cents/kWh, preserving

PSNH’s low-cost generation fleet Investment recovered through PSNH generation rates

Merrimack Scrubber Required by New Hampshire

statute for mercury emissions reductions

Estimated to cost $250 million Engineering, Procurement &

Construction (EPC) contract secured with Washington Group International in fall 2007

Construction start: 2009 Project completion: 2013

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NU Distribution Infrastructure Investments

2008 – 2012 investment Invest $2.5 billion in distribution

capital spendingCL&P: $1.5 billionPSNH: $525 millionWMECO: $175 millionYankee Gas: $300 million

Peak Load Growth & New Business Support – 44%

Basic Business Requirements - 31% Plant Relocations Equipment Failures Information Technology Other Capital

Aging Infrastructure - 25% Regulatory Commitments Reliability/Obsolescence Facility Upgrades

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Regulated Distribution Investments -- LNG Facility

LNG Facility Yankee Gas’s 1.2 Bcf liquid

natural gas production facility in Waterbury, CT

$108 million cost Completed in time for the 2007-

2008 heating season Enhances reliability and

insulates customers from price volatility

Lowers customer costs by $25 million a year

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Completed Distribution Rate Cases

Company StatusEffective

DateInitial

IncreaseAuthorized

ROE

PSNHSettled and approved

7/1/07 $46.6 million 9.67%

Yankee GasSettled and approved

7/1/07$22.1 million net

10.1%

WMECOSettled and approved

1/1/07$1 million plus trackers

Sharing outside

8-12%

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CL&P Distribution Rate Case

CL&P

Rate Increase$180 - $185 million in 2008

$22 million in 2009

ROE 11%

Capital Structure 45% equity (per rating agency)

DecouplingGuaranteed revenue/customer

No weather normalization

Distribution Capex $290 million/year

Tree TrimmingDouble to $25 million/year to support shorter clearing cycle

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Regulated Generation, Distribution and Transmission Projects Provide Savings for Customers

Regulated generation and distribution projects provide benefits in the form of increased reliability and reduced energy costs for customers

Northern Wood Power Project is dispatching power below market and 100% of our renewable energy certificates are sold for 2007

New Hampshire-owned utility generation has resulted in the lowest energy costs for customers in New England – 7.83 cents per kWh – 33% lower than current market

Yankee Gas LNG facility is complete and will lower costs to customers by $25 million a year

Transmission projects provide benefits in the form of increased reliability and reduced congestion and capacity market costs

Bethel-Norwalk has reduced Connecticut congestion costs by more than $150 million since October 2006

Middletown-Norwalk is expected to provide $20 - $30 million in avoided costs

NEEWS projects are expected to provide additional savings of at least $200 million per year in reduced congestion and capacity costs

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Emerging Challenges of Distribution Reliability

Dana Louth, CL&P Vice President – Energy Delivery

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NU’s Distribution Business

Highlighted area reflects service territory

CompanyTotal #

Distribution Customers

Net Distribution

Assets

The Connecticut Light and Power Company

1,200,000 $1,918,000

Public Service Company of New Hampshire

490,000 $925,000

Western Massachusetts Electric Company

200,000 $372,000

Yankee Gas 200,000 $666,000

TOTAL 2,090,000 $3,881,000 1

1 000 omitted

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$279$334

$291 $289 $298 $298

$125

$167

$144 $153$172

$252$34

$35

$40 $34$34

$34

$65

$57

$61 $60$62

$68

$0

$100

$200

$300

$400

$500

$600

$700

2007 2008 2009 2010 2011 2012

CL&P PSNH* WMECO Yankee Gas

*PSNH Generation = $36 million in 2007; $63 million in 2008; $44 million in 2009; $51 million in 2010;$66 million in 2011; and $142 million in 2012

$ M

illio

nsProjected Distribution and Generation Capital Expenditures

$503$536

$593

$566$536

$652

Total capital investments made in 2008-2012 will grow asset base by 39% after depreciation

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CL&P Distribution Infrastructure Investments

2008 – 2012 investment CL&P expects to invest $1.5 billion in

distribution capital spending Peak Load Growth & New Business =

$570 million Basic Business Requirements = $310

million Aging Infrastructure = $585 million

Peak Load Growth & New Business - 39%

Basic Business Requirements - 21% Plant Relocations Information Technology Other Capital

Aging Infrastructure - 40% Equipment Failures Reliability/Obsolescence Regulatory Commitments

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What is CL&P’s Aging Distribution Infrastructure?

(9%)(16%)

(12%)(18%)

(44%)

(9%)(13%) (10%)

(23%)

(45%)

29

42

49

0

10

20

30

40

50

60

0-30 31-40 41+

(41%)

(35%)

(24%)

Approximate Age of Metal Enclosed Switchgear

Number of Poles

Feet of Conductor

# of S/S

Plant that is relatively new

Plant that is beyond its useful life

Plant that is approaching the end of its useful life

Connecticut/New England saw much building/neighborhood development post-WWII Significant amount of plant is 50+ years old Average distribution plant age is 35 years

Approximate Pole Plant Age

61465

11206185406

125834

307489

-

50,000

100,000

150,000

200,000

250,000

300,000

350,000

0-10 11to 20 21-30 31-40 41+

Approximate Overhead Primary Conductor (ft)

3,2664,567

3,659

8,023

16,028

-

2,0004,000

6,000

8,00010,000

12,000

14,00016,000

18,000

0-10 11-20 21-30 31-40 41+

(44%)

(9%)(12%)

(16%) (18%)(9%) (13%) (10%)

(23%)

(45%)

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Why Won’t Distribution Infrastructure Last Forever?

Type of Plant Aging Issues Results In

Poles Wood decayMore failures,

customer interruptions,

and safety

concerns

OH WiresLoss of strength/connections degrade

UG Equipment Insulation failure/rust

SubstationsMechanical and electrical wear

and tear, spare parts

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How Much Distribution Equipment is Approaching the End

of its Useful Life?

40% of distribution plant is over 40 years old

Full replacement value of old obsolete plant at CL&P would cost about $5.2 billion

Asset Type Replace Cost

Overhead $3,829 Million

Underground $1,003 Million

Substation $ 330 Million

TOTAL $5,162 Million

CL&P 5-Year Plan vs. Aging Equipment Replacement Cost

5-Year Plan Replacement Cost

$0.6 Billion

$5.2 Billion

Total investment required to address major equipment at or approaching end of life in 2007

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What’s The Impact Of Aging Infrastructure On Reliability

Provided To CL&P Customers?

0

20

40

60

80

100

120

140

160

1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006

SA

IDI M

inu

tes

CL&P Trendline +/- One-Half Std Deviation

System Average Interruption Index (SAIDI) measures the average number of minutes a typical customer is without power

CL&P SAIDI - CTPUC Criteria

0 5 10 15 20 25 30 35 40 45 50

Tree Caused

Equipment Failure

Vehicle Accident

Animal

Lightning

No Problem Found

Action by Others

All Other

Employee Error

Planned Outage

Overload

Reliability is generally degrading and…. equipment failure associated with aging infrastructure is a major cause of

degrading reliability

CL&P 2006 SAIDI (Non-Storm) was 132.63 minutes.

Top three causes contributed 96.71 minutes

Major Factors Impact CL&P Distribution Reliability

SAIDI

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While An Aging Infrastructure Can Cause Degrading Reliability, Our

Customers Indicate They Will Not Accept Lower Reliability Levels

Distribution infrastructure improvements are needed to maintain reliable service “We are suffering from old infrastructure, where the lines and transformers are showing their age…That

affects the power we get.” *

Today’s digital economy requires reliable power “Brown outs or spikes is a problem for mechanical devices. Close to not having any power when it’s not

reliable.” *

Poor power quality adversely impacts our customers “We all agree that power is mission critical, got to have it to run your business no matter what it is.” *

Preventative maintenance is critical to equipment performance“Maintenance and uninterrupted service go hand-in-hand. You need the maintenance and the upkeep .” *

But….

Our customers are concerned about high rates.“Nothing else we do has gone up as much.” *

* Excerpts from Fall 2007 Customer Satisfaction Focus Group Study.

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Challenges Associated with Aging Distribution Infrastructure

Identifying significant vulnerabilities through risk management initiatives

Prioritizing work

Executing upgrades

Rising cost of labor and materials – impact of world-wide demand on commodities

Attracting and retaining engineering and technical staff

Avoiding customer inconvenience during project construction

Cost of preventive maintenance programs

Rate impact of replacing depreciated equipment

Securing reasonable regulatory treatment to avoid rate lag

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What is CL&P Doing to Address Distribution Infrastructure

Challenges?

Formed asset management organization

Created new major projects organization

Five-year capital investment plan

Formed vendor/supplier alliances

Partnerships with colleges/universities to develop power engineers

Upgrading inspection and maintenance plans

Working on strategies to moderate rate impact

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Summary

CL&P and other NU distribution companies have an aging delivery infrastructure

A comprehensive upgrade strategy is required

Risk management/prioritization

Capital and O&M allocation

Capital additions likely to rise from today’s level as is rate base

CL&P continues to work with regulators

Fair regulatory treatment is key

Documents

Northeast Utilities’ Five-Year Infrastructure Investment Plan Wall Street Access January 10, 2008