The Connecticut Light and Power Company (CNLTN) 8-K Power & Gas Leaders Conference

Merrill Lynch

Power & Gas Leaders Conference

September 25, 2007

Energy / Growth / Leadership

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.

2

A Successful 2007 In Meeting Our Short-Term And Long-Term
Goals

Short Term

23% increase through June 30 in regulated earnings, consistent with guidance

Rate settlements implemented at 3 of 4 utilities

Transmission projects on budget, on or ahead of schedule

2007 capital investment deployment increased

CL&P rate case filed

Competitive business divestitures largely complete

Longer Term

Rate base expectations intact

Design of next generation of transmission projects advancing

Potential new opportunities in New England

3

2007 Results Through June 30

Distribution and  

Regulated

Generation

Transmission

Parent/Other

Competitive

Total

14.2%

45.7%

$62.7

$25.4

($76.9)

$12.1

$71.6

$37.0

$7.6

$7.4

$123.6

$0.9

($100.0)

($80.0)

($60.0)

($40.0)

($20.0)

$0.0

$20.0

$40.0

$60.0

$80.0

$100.0

$120.0

$140.0

1H 2006

1H 2007

4

Status of Distribution Rate Cases

Sharing
      outside      
8-12%

$1 million
plus trackers

1/1/07

Settled and
approved

WMECO

10.1%

$22.1 million
net

7/1/07

Settled and
approved

Yankee Gas

9.67%

$46.6 million

7/1/07

Settled and
approved

PSNH

11%*

$189 million
in 2008*

1/1/08*

Filed 7/30/07

CL&P

ROE

Initial
Increase

Effective
Date

Status

Company

* Proposed

5

2007-2011 Projected Capital Expenditures

Distribution and Regulated Generation Capex

Transmission Capex

2006 Actual

2007 Est.

2010 Est.

2011 Est.

2008 Est.

2009 Est.

$908*

$779*

$874*

$1,265*

$1,126*

$880*

*Excludes approximately $18 million per year at corporate service companies

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

6

$1,055

$1,428

$1,920

$2,572

$2,761

$3,025

$3,466

$3,951

$4,218

$4,435

$4,675

$4,874

$0

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

$7,000

$8,000

Projected Transmission and Distribution Year-End Rate Base

Distribution and Regulated Generation

Transmission**

2006 Actual

2007 Est.

2010 Est.

2011 Est.

2008 Est.

2009 Est.

*  Rate base figures do not reflect August 2007 update for 2007 capital expenditures

**Transmission reflects FERC approved 50% CWIP for Southwest CT projects

Overall

Rate Base

2006-2011

CAGR of 12%

7% CAGR from
2006-2011

23% CAGR from
2006-2011

Supports EPS CAGR of 10-14%

$4,521

$5,379

$6,138

$7,007

$7,436

$7,899

7

Four Major Southwest Connecticut Projects – A $1.65 Billion Investment
More Than Half Complete

50% of CT
Load

Bethel-Norwalk

345-kV underground

& overhead

$350 Million

21 miles 345-kV               
(56% underground)

10 miles 115-kV            
(100% underground)

Completed October
2006 at a cost of $340
million

Expected to save over
$100 million in
congestion costs in
2007

Middletown-Norwalk 345-kV

underground & overhead

$1,047 Million (NU share)

Glenbrook Cables

115-kV underground

$183 Million

9 miles 115-kV underground

Projected in-service date:  2008

36% complete at 6/30/07

Long Island Cable

138-kV cross-sound

$72 Million (NU share)

11 miles 138-kV submarine cable

Joint project with LIPA

Projected in-service date:  2008

41% complete at 6/30/07

69 miles 345-kV  (35% underground)

57 miles 115-kV  (1% underground)

Joint project with United Illuminating

Projected in-service date:  Late 2009,
but timetable may be accelerated

38% complete at 6/30/07

8

Springfield-115
Projects

SPRINGFIELD

HARTFORD

345-kV Substation

Generation Station

345-kV ROW

115-kV ROW

Greater Springfield

Reliability Project

Central Connecticut

Reliability Project

Interstate

Reliability Project

The NEEWS Projects Expected to Better Connect Eastern, Western New England
By 2013; Estimated To Cost $1.1 - $1.4 Billion

9

Trends Within The New England Region

Increasing costs of electricity

Increased focus on energy efficiency

Increasing renewable portfolio standards

Regional Greenhouse Gas Initiative (RGGI) requirements

Upcoming need for new capacity

New England’s energy future requires a diverse set of energy solutions

10

New England Generation Mix

1994

2006

Nuclear

36.9%

Natural Gas

16.3%

Residual Oil

12.7%

Conv.

Hydro

5.3%

Purchases

8.9%

Other,

Net

4.5%

Coal

15.4%

Nuclear

27.5%

Natural Gas

29.9%

Coal

14.4%

Residual Oil

11.5%

Conv.

Hydro

5.7%

Purchases

4.6%

Other,

Net

6.4%

Source:  New England Power Pool and ISO-NE reports

Natural gas supplies 30% of energy mix, 38% of capacity mix,

sets clearing price 90% of the time

11

New England States Are Increasing Their Renewable Portfolio Expectations

CT:  27% by 2020

VT:  2005-2012              
Load growth to be met with
renewables and capped at
10%.  (This is not a binding
target, but a voluntary goal
for adopting renewable
energy.)

ME:  30% by 2000,
additional 10% new
resources by 2017.  
Total is 40%.

NH:  23.8% by
2025

RI:  16% by 2019

MA:  4% in 2009; 1%
annual increments
resulting in 20% by
2020

12

Beyond 2010, a growing gap in meeting New England Renewable
Portfolio Standards (RPS) is projected

17,269 GWh

2020

Decrease in
percentage of
existing renewables
is due to growth in
New England energy
requirements

By 2020, there is a 17,000 GWh gap between existing renewable resources and
RPS requirements

0%

5%

10%

15%

20%

25%

Year

RPS Requirements - %

Existing Renewables - %

13

Meeting the RGGI Requirements Will Be Challenging Under Any Load
Growth Scenario

Assuming current energy growth projections of 1.3% per year, by 2020 New England is projected to
produce CO ₂ emissions of nearly 74 million tons – about 24 million more than the RGGI cap

Lowering CO₂ emissions to meet RGGI requirements would require replacing about 36,000 GWh of existing CO₂-
emitting resources with low-emissions resources

This translates to about 5,000 MW of base load (80% capacity factor) low-emission generation

Even under a “zero” energy growth scenario, RGGI mandates reductions of about 10 million tons by
2020

This would require replacing about 12,000 GWh  -- 500 MW each of coal and oil and 1,200 MW of gas-fired
generation, assuming shutdowns proportional to New England’s current energy mix

1.3% energy growth

0% energy growth

RGGI Cap

New England CO2 Emissions

40

45

50

55

60

65

70

75

80

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

Year

New England RGGI CO2 Cap

Projected CO2 Emissions

14

Projected Summer Capacity Surplus/Deficiency in 2015

+2,800 MW

Long-term forecasts show a summer
surplus of generation in the eastern
provinces of Canada and insufficient
summer generation in Ontario, New
York, and New England.

Quebec, Newfoundland and Labrador
have identified over 21,000 MW of
renewable power potential (7,000
MW of hydroelectric and 14,000 MW
of wind).

This suggests there will be a growing
need for transmission to move
surplus energy from eastern Canada
into New England.

It also suggests that Ontario and New
York are also potential Buyers who
will be competing with New England.

Eastern Canada Will  Become A Valuable Source To Meet New England’s Needs

* Summer surplus, winter surplus 0 MW

-4,400 MW

Ontario

Quebec

Newfoundland

& Labrador

Maritimes

New

England

New

York

-5,000 MW

-4,000 MW

11,000 MW *

50 MW *

15

NU In Summary

Distribution business on track; rate settlements implemented

Transmission business growing rapidly; projects on track

2007 earnings on track

Focus on longer term opportunities

NU leveraging its leadership and expertise to meet New England’s energy challenges

16