Kansas City/Dallas Investor Meetings MARCH 2 & 3, 2010

1. Kansas City/Dallas Investor Meetings MARCH 2 & 3, 2010

2. Safe Harbor Provisions 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.

3. 2009 Results 13.6% * 5.6% 18.8% Earnings For Common In Millions * Distribution and Generation Transmission Competitive Total Parent/Other *Excludes $29.8 million after-tax charge from March 2008 litigation settlement

4. 2009 Distribution and Generation Results 5.7% 14.7% Earnings For Common In Millions 22.5% 35.8% CL&P Yankee Gas PSNH WMECO

5. Increased Transmission Investment Has Diversified and Significantly Increased Regulated Earnings 2005 2009 25.2% 50.8% $41.1 $164.3 $159.2 $122.3 74.8% 49.2% Net Income: $163.4 Regulated EPS: $1.24 Net Income: $323.5 Regulated EPS: $1.87 Regulated Net Income (In millions) Distribution/Generation Transmission

6. 2008 – 2009 Results, 2010 EPS Guidance *See appendix for GAAP/non-GAAP reconciliation

7. Key Earnings Drivers for 2010 - 2011

8. Balance Sheet Strengthened Considerably in 2009 12/31/08 12/31/09 (In millions) $116 $116 1.4% 1.4% $4,776 $4,660 38.2% 60.4% 42.8% 55.8% $3,020 $3,578 Total: $7,912 Total: $8,354 Total debt Common equity Preferred

9. History of Strong Dividend Growth Since 2001 Dividend policy ($) EPS Dividends paid/declared per share Payout ratios 62.5% $1.80–$2.00 $1.91 $1.86² 48.7% 49.7% $1.59 44.3% $1.16¹ $1.0253 $0.95 $0.825 $0.775 $0.725 1 Excludes net income of competitive businesses, one-time CL&P tax reduction 2 Excludes litigation settlement charge 3 Based on first quarter rate of $0.25625

10. Hydro-Quebec- HVDC HVDC Line between Quebec and New Hampshire 3 Connecticut Borders (MA, RI): NEEWS Projects Under Way 2 Southwest Connecticut Reliability: Projects Complete 1 Transmission as a Key Strategic Enabler to Solving New England’s Energy Challenges Renewable Collector Lines ´ Renewables & Clean Energy (ME/NH/VT): Projects in Development/ High Wind potential areas 4 ´

11. NEEWS Advances Into the Siting Phase • 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 Greater Springfield Reliability Project SPRINGFIELD Interstate Reliability Project HARTFORD Central Connecticut Reliability Project 345-kV Substation Generation Station 345-kV ROW 115-kV ROW

12. 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 updates since 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 Des Cantons HVDC Line HVDC Converter Station

14. Developing a Regional Renewable Solution for New England • Concept • Renewable Access Transmission Line • 2,000 MW • $1.5 billion to $2 billion New England Renewable Projections for 2020 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 Resources Required to Fill Shortfall in 2020 Wind (on-shore and off-shore) Other Class I Technologies Electricity Demand ~ 3,300 MW ~ 500 MW Wind Zone New Line

15. 2010-2014 Transmission Capital Expenditures Historic Forecast $2.8 Billion Up To $2.9 Billion HVDC Line from Canada US portion now estimated at $900 million with $675 million NU ownership share Successful completion of SWCT projects SWCT projects total $1.6 billion NEEWS projects ramping up In Millions NEEWS projects estimated at $1.35 billion during 2010-2014 forecast period $900 million of other projects (Details follow)

16. Capital Projects Reflected in Projected2010-2014 Transmission Year-End Rate Base Transmission Rate Base CAGR of 12% $4,673 $4,042 $3,513 $2,996 $2,680 $2,597 In Millions $2,402 * ** * * Reflects FERC approval of 100% CWIP for NEEWS projects **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 Service territories Total customers: 2.1 million Total assets: $14.1 billion • Regulated T&D company • 1.21 million retail customers in 149 cities and towns in Connecticut The Connecticut Light and Power Company VT NH • Regulated integrated electric utility • 496,000 retail customers in 211 cities and towns in New Hampshire • ~1,200MW of regulated generation assets Public Service Company ofNew Hampshire Electric territory The Connecticut Light andPower Company Public Service Companyof New Hampshire Western MassachusettsElectric Company • Regulated T&D company • 205,000 retail customers in 59 cities and towns in western Massachusetts Western Massachusetts Electric Company MA Gas territory Yankee GasServices 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) RI CT Yankee Gas Services Company Electric Gas 1 As of June 30, 2009

19. Electric Distribution and Generation Capital Expenditures – By Company 2010-2014 Projected Distribution & Generation Capital Spending $2.8 Billion $665 $594 $565 $546 $529 $513 In millions

20. Projected 2010 – 2014 Distribution and Generation Year-End Rate Base $6,384 Projected Distribution & Generation Rate Base CAGR of 8% $6,158 $5,877 $5,158 $4,763 $4,401 $4,071 In Millions

21. 2010 Rate Cases

22. Generation Strategy • 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 WMECO Solar Initiative The Clean Air Project • 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 2010-2014 Projected Yankee Gas Capital Spending $461 Million $112 $104 Yankee Gas Strategy $83 $82 $80 • 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) $60 In millions

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. Projected Transmission Capital Expenditures $806 $752 $626 $465 In Millions $273 $292

27. 2010-2014 Transmission Capital ProgramOther Projects – In Millions CL&P WMECO PSNH Total $897 Million Projects not yet in Regional System Plan (RSP) 298 • Breakdown of Other Projects: • 45% ($401M) - in RSP • 24% ($216M) - not required to be in RSP • 31% ($280M) - not yet in RSP 259 211 156 150 34 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

29. Beyond NEEWS, HQ Project, Significant TransmissionInvestment Will Be Needed to Bring Renewables to Market Current New England Renewable Portfolio Requirements 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 Massachusetts Class IClass II 4% in 2009; 1% annual 3.6% kwH sales starting increments thereafter in 2009 & 3.5% kwH sales from waste energy starting in 2009 Connecticut 27% by 2020 RI 16% by 2020

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