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
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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