1
Kansas City/Dallas Investor MeetingsMARCH 2 & 3, 2010
2
This presentation contains statements concerning NU’s 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. In some cases, a listener or reader can identify these 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, actions or inaction of local, state and federal regulatory and taxing bodies; changes in business and economic conditions, including their impact on interest rates, bad debt expense and demand for our products and services; changes in weather patterns; changes in laws, regulations or regulatory policy; changes in levels and 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; fluctuations in the value of our remaining competitive electricity positions; actions of rating agencies; 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 (SEC). 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 or to reflect the occurrence of unanticipated events.
This presentation includes non-GAAP financial measures referencing our 2008 earnings and EPS excluding a significant charge resulting from the settlement of litigation and our 2006 EPS excluding two significant, discrete impacts, which are the results of our competitive generation business that included a significant gain from the sale of such business and a reduction in income tax expense pursuant to a Private Letter Ruling issued by the Internal Revenue Service. Due to the nature and significance of these items, management believes that the relative non-GAAP presentation is more representative of our performance and provides additional and useful information to readers of this presentation in analyzing historical and future performance. This presentation also references actual and projected EPS by business, a non-GAAP presentation, which management believes is useful to investors to evaluate the actual and projected financial performance and contribution of our businesses. These non-GAAP financial measures should not be considered as alternatives to our consolidated net income attributable to controlling interests, and EPS determined in accordance with GAAP as an indicator of operating performance. Please refer to the reconciliations of these non-GAAP financial measures to our consolidated net income attributable to controlling interests, EPS included as an Appendix to this presentation.
Please refer to our reports to the SEC for further details concerning the matters described in this presentation.
Safe Harbor Provisions
3
$13.1
$138.3$150.8
$290.6
($11.6)
$330.0
$15.8($9.3)
$164.3$159.2
($25)
$25
$75
$125
$175
$225
$275
$325
$375
2008
2009
2009 Results
Distribution and Generation
Transmission Parent/Other Competitive Total
*Excludes $29.8 million after-tax charge from March 2008 litigation settlement
5.6% 18.8%
*
13.6%
Ear
nin
gs
Fo
r C
om
mo
n In
Mill
ion
s
*
4
2009 Distribution and Generation Results
$27.1
$41.4
$70.0
$12.3
$21.0
$16.7
$47.5
$74.0
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
2008
2009
CL&P PSNH WMECO Yankee Gas
5.7%
14.7%
Ear
nin
gs
Fo
r C
om
mo
n In
Mill
ion
s
35.8%
22.5%
5
Increased Transmission Investment Has Diversified and Significantly Increased Regulated Earnings
$41.1
$122.3$164.3
2005 2009
Regulated Net Income(In millions)
Distribution/Generation
Transmission
Net Income: $163.4Regulated EPS: $1.24
Net Income: $323.5Regulated EPS: $1.87
74.8%
25.2%
50.8%
49.2%
$159.2
6
2008 – 2009 Results, 2010 EPS Guidance
2008 Actual* 2009 Actual 2010 Guidance
Distribution/Generation $0.96 $0.92 $0.95 - $1.05
Transmission $0.89 $0.95 $0.90 - $0.95
Competitive $0.08 $0.09 $0.00 - $0.05
NU Parent/Other excluding litigation charge in 2008
($0.07) ($0.05) ($0.05)
NU Consolidated excluding litigation charge in 2008
$1.86 $1.91 $1.80 - $2.00
Litigation charge ($0.19) N/A N/A
NU Consolidated $1.67 $1.91 $1.80 - $2.00
*See appendix for GAAP/non-GAAP reconciliation
7
Key Earnings Drivers for 2010 - 2011
2010 2011
Positive Drivers
• CL&P, PSNH rate cases (2nd half only)
• PSNH Clean Air Project construction (AFUDC)
• Higher average transmission rate base
• CL&P, PSNH rate cases • WMECO rate case, solar investment• Possible Yankee Gas rate case • PSNH Clean Air Project construction
(AFUDC)• Greater Springfield Reliability Project
construction (cash return on CWIP)• Higher average transmission rate base
Pressures
• Pension costs• Uncollectible costs• Sales • Operating expenses• Expenses associated with
investments in aging distribution infrastructure
• Sales • Operating expenses• Expenses associated with investments
in aging distribution infrastructure• Roll off of profitable NUEI contracts
8
Balance Sheet Strengthened Considerably in 2009
12/31/08 12/31/09
$4,776 $4,660
$116 $116
$3,020
$3,578
Total debt Common equity Preferred
(In millions)
38.2% 60.4%
1.4%
42.8% 55.8%
1.4%
Total: $7,912 Total: $8,354
9
History of Strong Dividend Growth Since 2001
Dividend policy ($)
$0.00
$0.25
$0.50
$0.75
$1.00
$1.25
$1.50
$1.75
$2.00
$2.25
2006 2007 2008 2009 2010E
0.0%
10.0%
20.0%
30.0%
40.0%
50.0%
60.0%
70.0%
62.5%
48.7%
44.3%
49.7%
$1.80–$2.00
$1.86²
$1.16¹
$1.59
$0.825$0.775
$0.725
$0.95
Payout ratiosEPS Dividends paid/declared per share
1 Excludes net income of competitive businesses, one-time CL&P tax reduction2 Excludes litigation settlement charge3 Based on first quarter rate of $0.25625
$1.91
$1.0253
10
Southwest Connecticut Reliability: Projects Complete
1
Connecticut Borders (MA, RI):NEEWS Projects Under Way2
Renewables & Clean Energy (ME/NH/VT):Projects in Development/High Wind potential areas
4
Renewable Collector Lines
Hydro-Quebec-HVDC
3 HVDC Line between Quebec and New Hampshire
Transmission as a Key Strategic Enabler to Solving New England’s Energy Challenges
´
´
11
NEEWS Advances Into the Siting Phase
SPRINGFIELD
HARTFORD
345-kV SubstationGeneration Station345-kV ROW
115-kV ROW
Central ConnecticutReliability Project
InterstateReliability Project
Greater SpringfieldReliability Project
GSRP Status
• ISO confirmed need date in October 2009
• CT hearings completed; MA hearings completed
• Decisions and orders expected in spring/summer 2010
• Construction start in late 2010
• In-service 2013
IRP and CCRP Status
• Updated needs assessment expected by 3Q 2010
12
Greater Springfield Interstate*
CentralConnecticut*
File Municipal Consultation Filing (MCF) Late 2010
Conduct MCF outreach Late 2010
Hold open houses Early 2011
File siting application Late 20106-12 mo. Behind
Interstate
Complete Evidentiary hearingsLate 2011/ Early 2012
6-12 mo. Behind Interstate
Receive Decision and OrderCT – 3/2010
MA – Q3 2010Mid 2012
6-12 mo. Behind Interstate
Begin Construction Late 2010 2012**6-12 mo. Behind
Interstate
Expected In-Service 2013 20146-12 mo. Behind
Interstate
Estimated cost ($Millions)
Does not include $211M in ancillary projects$714 $250 $315
NEEWS Projects - $1.49 Billion Capital Investment (2009-2014)
NEEWS Projects Milestones (as of 2/23/10)
* Depends upon the timing of a favorable outcome to ISO’s reassessment of need and need dates, which is expected in the 3d quarter of 2010.
**Depends upon timing of favorable outcome of siting in three states (CT, MA and RI)
Represents schedule updatessince November 2009
13
New HVDC Line To Connect Hydro-Quebec Generation To New England Market
´
• Joint venture between NU (75%) and NSTAR (25%)
• 1,200 MW transfer capability
• Northern terminus at Des Cantons (Québec), southern terminus in central or southern New Hampshire
• Québec terminal will convert the power from AC to DC (rectifier)
• US terminal will convert the power from DC to AC (inverter)
• Capital cost estimate for US segment: $900 million ($675 million for NU share)
• Work proceeding on Transmission Service Agreement and Purchased Power Agreement
HVDC Line
Des Cantons
HVDC Converter Station
14
Resources Required to Fill Shortfall in 2020
Wind (on-shore and off-shore)
Other Class I Technologies
~ 3,300 MW
~ 500 MW
Developing a Regional Renewable Solution for New England
New Line
Wind Zone
Electricity Demand
Estimated Class I Renewable Resource Requirements for New England (GWh) by 2020 = 22,800 GWh
6,600 GWh = Existing Available Renewables
3,500 GWh = Currently Planned or Under Development
12,700 GWh = Unplanned Renewables/Balance Shortfall
Class I Technologies include:
> Biomass/Biofuels > Fuel Cells (CT)
> Landfill Gas > Small Hydro
> Solar PV > On and Offshore Wind
Concept• Renewable Access
Transmission Line• 2,000 MW• $1.5 billion to $2
billion
New England Renewable Projections for 2020
15
2010-2014 Transmission Capital Expenditures
$0
$100
$200
$300
$400
$500
$600
$700
$800
$900
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
Base Reliability Major Southwest CT NEEWS HQ HVDC
Historic Forecast
In M
illio
ns
Up To $2.9 Billion $2.8 Billion
SWCT projects total $1.6 billion
$900 million of other projects(Details follow)
Successful completion of
SWCT projects
US portion now estimated at
$900 million with $675 million NU ownership share
HVDC Line from Canada
NEEWS projects estimated at
$1.35 billion during 2010-2014 forecast
period
NEEWS projects ramping up
16
Capital Projects Reflected in Projected2010-2014 Transmission Year-End Rate Base
$2,022 $2,134 $2,318 $2,545 $2,563
$250 $315 $335 $433$530
$608
$130$183 $240
$429
$665
$851
$2,099 $2,105
$584
$889
$675
$0
$500
$1,000
$1,500
$2,000
$2,500
$3,000
$3,500
$4,000
$4,500
$5,000
2008Actual
2009Actual
2010 2011 2012 2013 2014
CL&P PSNH WMECO Transmission from Canada
Transmission Rate Base
CAGR of 12%
In M
illio
ns
$2,402$2,597
$2,996
$3,513
$4,042
$4,673
* Reflects FERC approval of 100% CWIP for NEEWS projects
$2,680
**NU share of this project is depicted as traditional rate base without CWIP during construction
*** *
17
Regulated Distribution & Generation
18
Attractive Regulated Business Profile
Regulated companies
The Connecticut
Light and Power
Company
Yankee Gas Services Company
Public Service Company of
New Hampshire
Western Massachusetts
Electric Company
• Regulated natural gas delivery company with significant growth potential
• Largest natural gas distribution system in Connecticut as measured by number of customers (~205,000), and size of service territory (2,088 square miles)
• Regulated integrated electric utility
• 496,000 retail customers in 211 cities and towns in New Hampshire
• ~1,200MW of regulated generation assets
• Regulated T&D company
• 1.21 million retail customers in 149 cities and towns in Connecticut
• Regulated T&D company
• 205,000 retail customers in 59 cities and towns in western Massachusetts
Service territories
VTNH
MA
CT RI
Electric territory
The Connecticut Light andPower Company
Public Service Companyof New Hampshire
Western MassachusettsElectric Company
Gas territory
Yankee GasServices Company
Total customers: 2.1 million
Total assets: $14.1 billion
Electric Gas1 As of June 30, 2009
19
$283 $311 $313 306 305 317
$99$113 $111 115 121 134$38$34 $39 36 35
145
187117
82 68 26
$20
$147
36
$0
$100
$200
$300
$400
$500
$600
$700
2009Actual
2010 2011 2012 2013 2014
WMECO - Solar ($41m total)
PSNH - Generation ($480m total)
WMECO - Distribution ($180m total)
PSNH - Distribution ($594m total)
CL&P - Distribution ($1,552m total)
In
mill
ions
Electric Distribution and Generation Capital Expenditures – By Company
2010-2014 Projected Distribution & Generation Capital Spending$2.8 Billion
$565
$513$529$546
$594
$665
20
Projected 2010 – 2014 Distribution and Generation Year-End Rate Base
$1,975 $2,119 $2,333 $2,497 $2,629 $2,778 $2,911
$667$772
$849$941
$1,030$1,090
$1,156
$374$412
$413$434
$447$456
$685$691
$764$843
$892$932
$974
$370$407
$404$443
$879$902
$882
$461
$0
$1,000
$2,000
$3,000
$4,000
$5,000
$6,000
2008Actual
2009Actual
2010 2011 2012 2013 2014
CL&P Distribution PSNH Distribution
WMECO Distribution Yankee GasPSNH and WMECO Generation
Projected Distribution & Generation Rate Base
CAGR of 8%
In M
illio
ns
$4,071
$4,763$5,158
$5,877$6,158
$6,384
$4,401
21
2010 Rate Cases
PSNH CL&P WMECO
Filing: Application filed 6/30/09 Application filed 1/08/10 Estimated 7/1/10
Key Topics:
• Rate lag• Ice storm cost recovery• Low earned ROE• Little sales growth• Rate base adds
• Aging infrastructure
• Sales declines
• Uncollectible expense
• Headroom from RRB final amortization in December 2010
• Decoupling
• Pension tracker
• Decoupling
• First full rate case in nearly 20 years
• Sales declines
• Rate base adds
Anticipated Completion Date:
7/1/10 7/1/10 1/1/11
Key Interim Dates
4/9/10: Target for settlement filing
4/20/10 – 4/22/10: Hearing
3/15/10 – 4/19/10: Hearings
5/21/10: Draft decision
6/4/10: Final decision
N/A
2009 Regulatory ROEs
7.2%
Distribution and Generation
3.6%
Distribution only
7.3% 8.4%
22
Generation Strategy
WMECO Solar InitiativeWMECO Solar InitiativeThe Clean Air ProjectThe Clean Air Project
Installation of 6 MW solar projected by 2012
First site (Pittsfield) announced in February
Estimated cost: $41 million
Constructive regulatory model – fully tracking, segmented rate base
Potential for up to 50 MW
Scrubber must be installed by 7/1/13 Will remove 90+% of sulfur, 80% of
mercury emissions Estimated cost: $457 million
Nearly $147 million capitalized at 12/31/09
Broad stakeholder support On or ahead of schedule: 40%
complete as of 2/28/10 Resolved major uncertainties
23
Yankee Gas Capital Expenditures
$23 $23 $22
$17 $22 $22 $25 $28 $30
$26$31
$31$31$32$34
$17
$17$23
$31$36
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
$110
$120
2009Actual
2010 2011 2012 2013 2014
Aging Infrastructure Basic BusinessPeak Load / New Business WWL
2010-2014 Projected Yankee Gas Capital Spending$461 Million
Investing $461 million, leveraging natural gas as “the fuel of choice”
Distribution system expansion: $67 million, 16-mile Waterbury-to-Wallingford Line (WWL)
Sales growth opportunities to supply renewable generation (fuel cells, DG)
Yankee Gas StrategyYankee Gas Strategy
$60
$83$82$80
$104$112
In
mill
ion
s
24
Additional Initiatives Meeting Public Policy Direction
CL&P concluded a 3,000 customer AMI/rate pilot on 8/31/09 to test the technology and customer interest in dynamic pricing rates
• Good customer response
• Gained insight on customer behavior in response to dynamic pricing rates and enabling technology
• Filed results with DPUC on December 1, 2009
• Future recommendations by March 31, 2010
WMECO Smart Grid pilot plan filed with DPU on October 16, 2009
• 1,750 customer pilot - $7 million projected cost
• DPU decision expected in first half of 2010
Electric vehicle infrastructure
25
Appendix
26
$163 $136$203
$281 $286
$155
$61$55
$118
$107 $74
$22
$68$66
$256
$328
$156
$49
$90
$236
$282
$6
$16
$0
$100
$200
$300
$400
$500
$600
$700
$800
$900
2009 Actual 2010 2011 2012 2013 2014
CL&P PSNH WMECO Transmission from Canada
Projected Transmission Capital Expenditures
$292
$806
$752
$465
$626
$273
In M
illio
ns
27
Other Transmission Capital Projects in RSP, Not in RSP or Not Required to be in RSP
$0
$50
$100
$150
$200
$250
$300
$350
2009 2010 2011 2012 2013 2014
Not Required to be in RSP In RSP Not Yet in RSP
2010-2014 Transmission Capital ProgramOther Projects – In Millions
CL&P WMECO PSNH
Total $897 Million
150
259298
156
34
211
Projects not yet in Regional System Plan (RSP)
Breakdown of Other Projects:
• 45% ($401M) - in RSP
• 24% ($216M) - not required to be in RSP
• 31% ($280M) - not yet in RSP
Stamford Area Reliability $100.0 Berkshire Area Solution $170.0 Manchester Area Solution $52.3Manchester - East Hartford Line $53.4 115 KV Relay Replacements $14.4 Scobie - Tewksbury Line $52.0Southwest CT Upgrades $30.0 115 KV Reliability Project $4.0 Nashua Area Solution $51.1115 KV Relay Replacements $28.3 CCVT Replacements $3.2 Deerfield 2nd Auto Transformer $42.8South Meadow BPS $13.1 13 Additional Reliability Projects $11.6 Maine Power Reliablity $30.8CCVT Replacements $11.3 Deerfield - Webster - Coolidge $30.0Spare Bethel -Norwalk Shunt Reactor $9.8 Northern Loop $23.0Transmission Operations Center $7.7 Thornton Ferry Substation $27.7Vehicle Purchases $7.4 OPGW Communications Project $16.0New Sherwood Substation $7.2 New Pease Substation $6.048 Additional Reliability Projects $50.7 29 Additional Reliability Projects $43.1
$318.9 $203.2 $374.8
Note: Upon commencement of the ISO-NE approval process, the HVDC project will be included in the RSP
28
2005-2009 NU Consolidating EPS GAAP / Non-GAAP Reconciliation
2005 Actual
2006 Actual
2007
Actual
2008
Actual
2009
Actual
Distribution/Generation $0.93 $0.80 $0.94 $0.96 $0.92
Transmission 0.31 0.39 0.53 0.89 0.95
Total Regulated 1.24 1.19 1.47 1.85 1.87
NU Parent/Other (0.14) (0.03) 0.04 (0.07) (0.05)
Total Regulated and Parent $1.10 $1.16 $1.51 $1.78 $1.82
Competitive (3.03) (0.63) 0.08 0.08 0.09
NU Consolidated Operating Results (Non-GAAP) ($1.93) $0.53 $1.59 $1.86 $1.91
CL&P Income Tax Reduction N/A 0.48 N/A N/A N/A
Gain on Sale of Competitive Generation N/A 2.04 N/A N/A N/A
Litigation Charge N/A N/A N/A (0.19) N/A
NU Consolidated GAAP ($1.93) $3.05 $1.59 $1.67 $1.91
29
Beyond NEEWS, HQ Project, Significant Transmission
Investment Will Be Needed to Bring Renewables to Market
Connecticut
27% by 2020
Vermont
Goal: 20% by 2017
Minimum: 2005-2012. Load growth to be met with renewables and capped at 10%.
Maine
40% by 2017 (currently 30%)
New Hampshire
23.8% by 2025
RI
16% by 2020
Massachusetts
Class I Class II 4% in 2009; 1% annual 3.6% kwH sales startingincrements thereafter in 2009 & 3.5% kwH
sales from wasteenergy starting in 2009
Current New England Renewable Portfolio Requirements
30
Understanding Terms Related to the HVDC Project
• Joint Development Agreement (JDA)• Defines the terms on which we will jointly manage the development of the HVDC line with HQ-TransEnergie
• Design, engineering, siting, permitting, obtaining or preparing written cost estimates• Creates a project board with general oversight responsibility for the project• Describes the roles and responsibilities of the project board and each company’s project managers• Defines project communication protocols• Will be in place through siting approval (a separate joint construction agreement will likely be needed)• Commercial agreement not subject to regulatory review
• Transmission Service Agreement (TSA)• Sets forth the terms and conditions under which HQ will acquire and pay for the transmission use rights over the New Hampshire
segment of the HVDC line• Describes what transmission rights HQ gets (firm rights to flow power, interruption or curtailment details)• Defines process for HQ to offer the transmission rights to others at times when they might not be using the line• Defines payment terms for the line• Defines the components of the cost for the line (revenue requirements: depreciation, ROE, debt service, O&M, property taxes)• Describes needed arrangements with ISO-NE such as scheduling flows over the line, etc.)• Subject to FERC review and approval
• Power Purchase Agreement (PPA)• Defines the product HQ will sell• Defines the pricing structure for the energy• Defines the pricing structure for capacity• Defines pricing for externalities• Sets forth payment terms • Negotiations under way with expected completion in spring 2010, with state regulatory filings sequenced to coincide with ISO,
technical and state specific timetables
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