1

Rating Agency MeetingsAPRIL 20, 2010

2

Today’s Agenda

• 2009 review

• ERM initiatives

• Transmission segment

• Distribution and generation segment

• Financing requirements

• Financial forecast

3

Key Achievements Over the Past Year

• Solid execution of strategic initiatives

• Earnings, cash flow well ahead of forecast

• Key rate case filings made

• Strong operational performance

• Strong interest in recent financings

4

Near Term Financing Complete

• PSNH $150 million bond issue closed on 12/14/09• 3 times oversubscribed• Coupon of 4.5%• Ten-year maturity

• WMECO $95 million senior unsecured issue closed on 3/8/10• 2 times oversubscribed• Coupon of 5.1%• Ten-year maturity

• CL&P $62 million PCRB remarketing closed 4/1/10• 6 times oversubscribed• Coupon of 1.4%• One-year mandatory put

• Yankee Gas $50 million first mortgage bond is expected to close on or about 4/22/10• 2.7 times oversubscribed• Coupon of 4.87%• Ten-year maturity

• Syndication of new $900 million of bank revolvers to commence shortly

5

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

6

$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

*

7

Competitive Business Performance Strong During Unwinding

• $15.8 million of net income in 2009

• Net income up 20.6% from 2008

• Forecast had been $8.2 million

• Strong management of wholesale contracts

• $3.8 million of net after-tax mark-to-market gains

• 2010 earnings projected to be $7.1 million, cash flow projected to be

$7.7 million

• 2011-2014 cash flow negative

• Wholesale contracts roll off in 2012, 2013

8

2009 Results vs. April 2009 Forecast

$millions NU Consolidated CL&P PSNH WMECO Yankee Gas

Forecast Actual Forecast Actual Forecast Actual Forecast Actual Forecast Actual

Earnings for common $305 $330 $191 $211 $68 $66 $24 $26 $29 $21

Ending common equity

$3,534 $3,578 $2,373 $2,373 $788 $727 $243 $247 $336 $331

Ending total debt $5,008 $4,602 $2,589 $2,582 $861 $863 $382 $384 $455 $362

Interest ex. RRBs $248 $237 $140 $137 $40 $33 $15 $15 $23 $22

FFO before working capital changes and after RRB amortization

$752 $853 $430 $519 $137 $157 $45 $69 $63 $71

* Excludes $57 million of WMECO long-term debt offset by spent nuclear fuel trust assets** Excludes $288 million of equity associated with acquisition premium

* *

**

*

**

*

Better than forecast Weaker than forecast

9

$1.59$1.67

$1.91$1.97

$0.775$0.825

$1.175$1.250

$1.325

$2.55

$2.73

$2.22

$2.35

$0.95$1.03

$1.10

48.7% 49.4% 49.7%

52.3%

49.5% 50.0%49.0%

48.5%

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

2007 2008 2009 2010 2011Est.

2012Est.

2013Est.

2014Est.

0.0%

10.0%

20.0%

30.0%

40.0%

50.0%

60.0%

NU Continues to Target a Conservative 50% Dividend Payout Ratio

Payout ratiosEPS Dividends per share

10

ERM is in its fifth year of implementation at NU

ERM works directly with the businesses and corporate shared services functions

Internal Risk Assessment Teams are used to identify, discuss and assess risks; Accountability for risk mitigation remains with the businesses and corporate shared services functions

Regular reports are made to the Board of Trustees on strategic, financial, and operational risks

ERM facilitates a fully functioning Risk and Capital Committee which integrates risk with capital expenditure decisions

ERM principles integrated into strategic planning and budgeting processes with strategic and operating plans “risk rated”

Enterprise Risk Management Status Update

Board of Trustees

Chief ExecutiveOfficer

Chief Financial

Officer

DirectorCorporate

ERM

Risk & Capital

Committee

Distribution/Generation

Risk Controller

Corporate Shared ServicesRisk Controller

TransmissionRisk

Controller

Select EnergyRisk

Controller

Executive VicePresident

Operations

Chair RiskAssessment

Teams

RiskAnalyst

Corporate ERM Group

11

NU’s Risk and Capital Committee (RaCC)

What are the RaCC’s Roles and

Responsibilities?

What is the RaCC? The RaCC is NU’s Risk Committee, where key financial, operational, strategic and business risks are

reviewed and discussed.

The RaCC is also NU’s Capital Committee, where capital projects are reviewed and approved per specific guidelines and with a risk perspective. Only the RaCC can authorize spending on certain capital projects or programs in excess of $10 million

Members and Advisors

Responsible for oversight of Enterprise Risk Management and the implementation of the NU Risk Management Policy and Capital Approval Policies and Procedures

Meets monthly or as needed

Reviews all capital projects and programs to recommend for CEO approval. Projects and programs exceeding $50 million are also sent to the NU Board for their review

Reviews all risk assessments in accordance with the NU Risk Management Policy

Members

Executive VP and CFO (Committee Chair)

Executive VP and COO

Senior VP and General Counsel

Senior VP, Enterprise Planning & Development

VP Human Resources

VP Shared Services

Chairman, President and CEO (non-voting)

Assistant Secretary (non-voting)

Advisory Team

Director - ERM

VP and Treasurer

VP – Accounting and Controller

VP – Rates and Regulatory

VP Finance

Director Internal Audit and Security

Secretary, Chief Compliance Officer and Deputy General Counsel

Assistant General Counsel

Executive Director Business Financial Services

ERM Business Unit Risk ControllersGuiding Documents

RaCC Charter

NU Risk Management Policy

Capital Approval Policies and Procedures

12

Key Themes for March 2010 Update of Strategic Risks

• Rates & Regulatory: Principal focus is on rate case outcomes for CL&P and PSNH; settlement options are being discussed and rate case planning for WMECO and Yankee Gas is underway. Cost-cutting efforts and ongoing education, discussions and other communications with key stakeholders are additional mitigations.

• Policy Changes: Companies continue to monitor potential national energy policy, including carbon legislation and an interconnection-wide transmission planning process and cost allocation. PSNH continues its RGGI program.

• Capital Deployment: Work to advance NEEWS continues, with positive approval from the Massachusetts Environmental Policy Act office stating that the proposed route for Greater Springfield (GSRP) portion of NEEWS is preferred, thus opening the door to siting and other required federal and state environmental permitting agency actions on applications. Advancement of the HQ HVDC project is ongoing, with negotiations on key documents underway and NU working closely with the NH legislature and its Transmission Committee.

• Operations: Risk of underinvestment in infrastructure remains a concern. 2009 scheduled maintenance was completed. While resolution efforts continue, uncollectibles remain high. Meetings with MA DEP are occurring to evaluate next steps with HWP remediation site.

• Financial: Bank liquidity and short-term debt costs are high relative to pre-recession levels, but have been improving. The IRS issued final guidance providing flexibility to switch approaches for calculating the present value of pension benefit obligation. Based on the results of the asset/liability study a new asset allocation policy was recommended to the Pension Committee with the goal of reducing the Plan’s exposure to equity market volatility and implementation began in Q4 2009.

• Customer Experience: Customer Experience has launched a receivables collection process improvement initiative and has implemented various plans to address call volume and longer hold times. The creation of the Customer Retention Index provides insight to the customer impact of our business processes.

• Business Continuity: Lessons learned from the pandemic outbreak in spring 2009 were used to improve plans and to make decisions regarding stockpiles of supplies, etc. New - Business Continuity Plans were enacted during a recent event regarding unidentified material in package delivered to Berlin offices.

13

Key Themes for March 2010 Update of Strategic Risks

• Information Technology: The IT Security Program continues to improve policies, processes and technology that address the evolving threats to NU’s enterprise. Employees’ personal devices pose some additional security risks. In addition, maintaining costs is challenging in an environment with continued need for outside services.Purchasing worked in collaboration with IT to develop a vendor web security questionnaire to ensure that the vendor that is hosting or managing company data meets the system security requirements. Purchasing also worked with Legal and IT Security to ensure compliance with new CT and MA laws regarding employee and customer personal information.

• Purchasing: To mitigate the impact of large project cancellations/delays, Purchasing continues to support the procurement of NEEWs materials and has begun bidding and awarding construction contracts. Major materials and equipment associated with NEEWs were awarded as blanket orders. New contracts achieved price reductions for certain assets and were awarded to multiple suppliers, mitigating the risk of insufficient supply to manufacturer default. Contractor of choice contracts (COC) were rebid in Q4 2009 and awarded in Q1 and Q2 2010. New rules, policies and work procedure were introduced and accepted by our COC contractors.

• Human Resources: Specific training programs to improve trust, strategic thinking, develop leadership expectations, and improve customer service leadership and communication have been implemented. HR will continue to work with Purchasing and investigate stop loss coverage in the event that a future pandemic could present significant financial impact due to high numbers of medical claims. Action has been taken to draft, revise or write policies to protect confidential information, including personal information.

• Accounting: IFRS training was conducted and a plan for IFRS Implementation is being developed. As part of the implementation of the CPM tool, a change management plan is being followed to address the changes in business processes due to this new technology and provide detailed training and timely communications. No significant SOX deficiencies or weaknesses in internal controls were identified in 2009.

• Legal: Momentums on several risks move to slightly favorable based on reviews and revisions to policies and procedures, enhanced controls and additional training. PCB disposal risk underwent root cause analysis and resulted in increased focus on leaking equipment. Cyber risk insurance has been purchased.

14

Transmission Segment

15

Transmission Segment Continues Its Strong Performance

• 2009 financial performance ahead of projections

• Continued strong operations and regulatory audits

• Initial NEEWS approvals received in March 2010

• FERC issued declaratory order in May 2009 supportive of HQ project structure; reaffirmed order in December 2009

• Capital program reduced due to reductions in PSNH spending

• Regional initiative developing to unlock renewable potential of Northern New England

16

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

17

$0

$200

$400

$600

$800

$1,000

$1,200

2009 2010 2011 2012 2013

Base Reliability NEEWS HQ HVDC Major Southwest CT

$0

$200

$400

$600

$800

$1,000

$1,200

2010 2011 2012 2013 2014

Base Reliability NEEWS HQ HVDC

Five-Year Transmission Capital Expenditures

Program Reduced By More Than $500 Million

2010 Forecast$2.9 Billion

2009 Forecast$3.4 Billion

In M

illio

ns

In M

illio

ns

18

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

Components of Other Projects

CL&P WMECO PSNH

Total 2010-2014 $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

In M

illio

ns

19

Capital Projects Reflected in Projected2010-2014 Transmission Year-End Rate Base

$2,099 $2,304 $2,542 $2,555

$315 $348 $405$463

$533 $580$183 $267

$459

$731

$959

$675

$2,082 $2,123

$919

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

$4,000

$4,500

$5,000

$5,500

$6,000

2009 Actual 2010 2011 2012 2013 2014

CL&P PSNH WMECO HQ HVDC

Transmission Rate Base

CAGR of 12.6%

In M

illio

ns

$2,597

$2,986

$3,499

* Reflects FERC approval of 100% CWIP for NEEWS projects

$2,697

**NU share of this project is depicted as traditional rate base without CWIP during construction

*** *

$4,035

$4,729

20

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

´

´

21

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 approved project in March 2010

• MA hearings complete and briefs filed, decision and order expected in late summer 2010

• Construction start in late 2010

• In-service 2013

IRP and CCRP Status

• Updated needs assessment expected by 3Q 2010

22

Greater Springfield Interstate*

CentralConnecticut*

FERC approval of financial incentives November 2008 November 2008 November 2008

File Municipal Consultation Filing (MCF) Late 2010

Hold open houses Early 2011

File siting application Late 20106-12 mo. Behind

Interstate

Complete Evidentiary hearingsLate 2011/ Early

20126-12 mo. Behind

Interstate

Receive Decision and OrderCT –

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

* Depends upon the timing of a favorable outcome to ISO’s reassessment of need and need dates, which is expected in the 3rd quarter of 2010.

**Depends upon timing of favorable outcome of siting in three states (CT, MA and RI)

23

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

24

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-NE,

technical and state specific timetables

25

Regulated Distribution & Generation

26

Distribution and Generation Segment Opportunities and Challenges

• Net income rose at electric distribution companies, but returns still disappointing

• All companies have strong pass-through mechanisms, but electric distribution operations require rate relief to improve returns

• Good success managing controllable O&M, but pension and uncollectible expenses have weighed down returns

• Sales growth outlook strong for Yankee Gas, weak for electric companies

• Generation business model meeting public policy mandates and producing reasonable returns

27

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%

28

-3.8%

-2.2%

6.9%

-2.1%

-1.4%

-3.4%

5.0%

-1.1%

0.9%0.3%

-4.8%

-1.6%

-6.0%

-5.0%

-4.0%

-3.0%

-2.0%

-1.0%

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

6.0%

7.0%

2009 vs. 2008 actual 2009 vs. 2008 weather normalized 2010 projected vs. 2009 weather-normalized

Sales Data and Projections

CL&P PSNH WMECO Yankee Gas

29

0.60%

0.40%

1.75%1.63%

0.76%

1.09%0.93%

1.82%

2.84%

1.27%

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

3.0%

CL&P PSNH WMECO Yankee Gas Composite

2008 2009

Write-Offs Rising, Reflect Each Service Territory’s Economic Conditions and Household Income

Writ

e-o

ffs

as

a %

of

Re

ven

ue

s

30

$283 $311 $332 $315 $305 $318

$99$113 $113 $118 $125 $133$38$34 $36 $38 $38

$145

$187 $121$79 $58 $29

$20$14

$7

$38

$0

$100

$200

$300

$400

$500

$600

$700

2009Actual

2010 2011 2012 2013 2014

WMECO - Solar ($41m total)

PSNH - Generation ($474m total)

WMECO - Distribution ($184m total)

PSNH - Distribution ($602m total)

CL&P - Distribution ($1,581m total)

In

mill

ions

Electric Distribution and Generation Capital Expenditures – By Company

2010-2014 Projected Distribution & Generation Capital Spending$2.8 Billion

$565

$518$526$557

$616

$665

31

Projected 2010 – 2014 Distribution and Generation Year-End Rate Base

$2,119 $2,334 $2,520 $2,705 $2,854 $3,022

$772$845

$933$1,035

$1,100$1,179

$411$421

$441$460

$474$484

$691$745

$829$873

$912$954

$407$446

$444

$874$883

$863

$0

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

$7,000

2009 Actual 2010 2011 2012 2013 2014

CL&P Distribution PSNH Distribution

WMECO Distribution Yankee GasPSNH and WMECO Generation

Projected Distribution & Generation Rate Base

CAGR of 8.1%

In M

illio

ns

$4,791

$5,166

$5,947$6,224

$6,503

$4,401

32

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

• 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 Dates4/23/10: Target for possible filing

of settlement

5/21/10: Draft decision

6/7/10: Final decisionN/A

2009 Regulatory ROEs

7.2%

Distribution and Generation

3.6%

Distribution only

7.3% 8.4%

33

PSNH, CL&P Rate Case Status

PSNH Rate Case Status

• $50.9 million permanent retroactive to 8/1/09 ($25.6 million actually took effect 8/1/09)

• $16.8 million effective 7/1/10

• Settlement discussions well advanced

CL&P Rate Case Status

• $133 million effective 7/1/10

• $44 million effective 7/1/11

• 2010 revenues deferred and recovered from 1/1/11 to 6/30/12

• Full amortization of RRBs ($234 million) and lower purchased power costs should result in significant rate decrease on 1/1/11

• Final decision due June 7

34

4.9466.021

7.185

10.125

12.076 11.666 12.14710.813

2.484

2.592

2.702

2.754

2.7862.879

3.293

3.293

0.35

0.468

0.468

0.664

0.717 0.679

1.293

1.446

1.549

1.702

2.174

2.511

2.2091.831

1.956

1.971

2003 2004 2005 2006 2007 2008 2009 2010 2011

Supply Distribution Transmission Other

Cents/KWH as of January 1

Current CL&P Rates Trending Down

2003-2009 Average Total Bill For All Customers Receiving Generation Supply From CL&PC

L&P

200

3 R

ate

Cas

e

17.52

10.783

16.054

12.529

17.05517.788

18.689

9.336

CL&

P 2

007

Rat

e C

ase

CL&

P 2

010

Rat

e C

ase

35

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: 48%

complete as of 3/31/10 Resolved major uncertainties

36

Yankee Gas Capital Expenditures

$22 $23 $22

$17 $22 $24 $26 $28 $30

$26$32

$30$29$29$35

$17

$18$17

$35$35

$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

• New shale-led supply paradigm

• Marcellus changes NE US gas markets

• Natural gas pricing “divorce” from oil

• Lower carbon footprint

• Low penetration rate in Yankee Gas franchise

• Potential significant savings for CT customers

Yankee Gas StrategyYankee Gas Strategy

$60

$82$80$77

$112$106

In

mill

ion

s

37

Five-Year Forecast

38

Significant Changes in Modeling Assumptions From 2009

• Lower five-year capital investment forecast ($6.4 billion vs. $7.0 billion)

• NEEWS and HQ projects completed in 2014 vs. 2013

• Smaller annual dividend increases (7.5 cents/yr. vs. 10 cents/yr.)

• NU share of HQ line to cost $675 million (vs. $525 million); still reflected as PSNH project, though likely to be in separate subsidiary

• Less sales growth

• Lower level of pension funding ($591 million vs. $884 million)

• Less equity issuance ($290 million vs. $871 million)

• Less net long-term debt issuance ($2.07 billion vs. $2.5 billion)

39

2009-2014: New Capital Expenditure Forecast

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

$1,800

$2,000

Five-year 2010-2014 capital spending of approximately $6.4 billion, compared with last year’s 2009-2013 $7 billion plan;

2009-2013 period down by $0.6 billion.

Five-year 2010-2014 capital spending of approximately $6.4 billion, compared with last year’s 2009-2013 $7 billion plan;

2009-2013 period down by $0.6 billion.

Distribution and Generation Capex (2009 Forecast)

Transmission Capex (2009 Forecast)

Distribution and Generation Capex (2010 Forecast*)

Transmission Capex (2010 Forecast)

2009 2012 20132010 2011$1

,662

$1,6

70

$851

$1,1

74

$1,2

11

2014

$1,0

96

$1,3

74

$1,4

40

$1,4

39

$1,1

12

$969

*Includes total capex at corporate service companies on behalf of operating companies of $134 million ($48 million in 2010, $25 million in 2011, $22 million in 2012, $25 million in 2013, and $14 million in 2014).

In M

illio

ns

40

Cash Flow To Cover More of Cap Ex After 2009 Actual

$921$988

$1,299$1,373 $1,384

$1,043$945

$764

$664$684$771

$1,067

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

2009 Actual 2010 2011 2012 2013 2014

Funds from operations Capital expenditures, ex. cost of removal

Actual/Projected Cash From Operations(Excluding RRB Retirements)

In M

illio

ns

41

Projected Consolidated Balance Sheet

57.2% 59.7% 58.9% 60.0% 59.8%

41.6% 39.1% 40.1% 39.0% 39.3%

1.3%1.1% 1.0% 1.0% 0.9%

0.0%

10.0%

20.0%

30.0%

40.0%

50.0%

60.0%

70.0%

80.0%

90.0%

100.0%

2010 2011 2012 2013 2014

Total Debt Preferred Common Equity

Ye

ar-

En

d B

ala

nce

S

he

et

42

Projected Consolidated FFO to Total Debt

9.8%

15.4%14.4%

12.0%

13.7%12.7%

11.8% 12.4%13.5%

0.0%

5.0%

10.0%

15.0%

20.0%

2010 2011 2012 2013 2014

2009 Forecast 2010 Forecast

Includes pension funding payment

43

Projected Consolidated FFO to Total Debt

14.6%15.9%

15.2%13.9%

13.7%13.9% 14.5%

13.7%13.8%

0.0%

5.0%

10.0%

15.0%

20.0%

2010 2011 2012 2013 2014

2009 Forecast 2010 Forecast

Excludes pension funding payment

44

Projected Consolidated FFO Interest Coverage

2.72.9 2.9

3.9

3.1 3.03.2 3.3

2.8

0.0

1.0

2.0

3.0

4.0

5.0

2010 2011 2012 2013 2014

2009 Forecast 2010 Forecast

Includes pension funding payment

45

Projected Consolidated FFO Interest Coverage

3.43.2

3.0

4.0

3.53.2

3.4 3.4

3.0

0.0

1.0

2.0

3.0

4.0

5.0

2010 2011 2012 2013 2014

2009 Forecast 2010 Forecast

Excludes pension funding payment

46

Appendix

47

Risk Mitigation Implementation Status Risk Momentum

1S Unfavorable regulatory decisions result in unsupported programs, O&M, and investment levels, which (1) affect the ability of our distribution companies to achieve fair and reasonable rates of return; (2) impair safety, reliability and customer experience; (3) expose the company to penalties and prudency reviews; and (4) limit the ability to raise new capital.

CL&P filed a multi-year distribution rate case in January 2010 that increases rates coincident with a decrease in the CTA, thus creating no net impact on customers’ total bills.

PSNH was able to settle a temporary rate case, setting the stage for permanent rates to be retroactive to August 1, 2009. PSNH has filed a permanent case. Settlement with the NHPUC staff and OCA may be possible.

Operating companies also continue to communicate and educate stakeholders and state regulators.

2S Volatility in energy prices and a weak economy draw greater attention to the cost of electricity.

Overall, economic conditions will affect the political environment for rate increases in 2010. NU’s mitigation focus has been on demand response programs to help customers manage energy costs and the utilization of wholesale power sourcing to manage supply price volatility. Power costs have decreased significantly and continue to gradually decline.

NU has also rolled out an integrated communications strategy to strengthen company reputations among key stakeholders, including regulators, politicians, and our customers.

3S Changes in regulatory and/or legislative policy and rate recovery mechanisms jeopardize the NU generation, distribution, and transmission businesses’ abilities to secure adequate and timely recovery of prudently incurred costs.

There are no pending changes in legislative policy that would impact the operating companies’ abilities to secure adequate and timely recovery of prudently incurred costs, but the economy and previous CL&P customer service issues add risk to recovery of prudently incurred costs.

The operating companies continue to build and maintain contacts with key legislative, regulatory and governmental leaders to educate them on the importance of financially healthy distribution companies in maintaining and strengthening electric reliability and the importance to the economic strength of the states that they operate in.

Strategic Risk Momentum Summary – March 2010

Neutral

Slightly Favorable

Slightly Unfavorable

Dashed arrow is March 2010 updateSolid arrow is December 2009 update

Rate case outcomes are critical, with CL&P and PSNH cases underway and WMECO planned for later in 2010. Cost management and resolution of uncollectibles balances remain a focus. Work to advance NEEWS projects continues.

48

Risk Mitigation Implementation Status Risk Momentum

4S The aging infrastructure of NU’s distribution system requires additional capital investment and O&M expense, thereby requiring additional rate relief.

Programs are underway at all three electric distribution companies to mitigate the aging infrastructure risk, including the NU Maintenance Standardization Initiative and the Distribution Capital Investment cross-functional team.

5S A weak economy and an increased focus on conservation and/or self generation results in continued sales erosion, increases in bad debt, uncollectible, and operating expenses, and has negative cash flow impacts.

Uncollectibles remain a problem for the operating companies, and focus on resolution continues. In January 2010, Customer Experience created the Receivables Recovery initiative to address issues with the receivables process.

2010 rate case proposals consider decoupling of sales and revenue.

The operating companies continue to control spending as a mitigation.

6S Substantial delays in, displacement or cancellation of transmission projects result in revised scope and cost and lower capital spending.

NU continues to actively demonstrate to key stakeholders the need for Transmission Projects through relationship building, technical analyses and education. Focus to advance the NEEWS projects through the siting and permitting process continues with a positive approval from the Massachusetts Environmental Policy Act office, but overall remains challenged. Enhanced planning efforts to document need and contingencies and to economically evaluate all options for Connecticut ratepayers is underway. Enhanced communications campaign efforts continue.

7S Changes in regulatory and/or legislative policy (including changing leaders/members) limit NU's ability to influence local and regional energy policy.

Legislation in the US Senate provides for an Interconnection-wide transmission planning process and cost allocation. This could diminish New England’s voice in its own transmission planning needs as well as reduce the voice of NU, and could result in cost shifts between the Midwest and New England. NU remains active with local, state, regional and federal policymakers to educate them on our objectives.

Strategic Risk Momentum Summary – March 2010

Slightly Favorable

Slightly Unfavorable

Slightly Unfavorable

Slightly Favorable

49

Risk Mitigation Implementation Status Risk Momentum8S NU proposed transmission solutions

to address RGGI and RPS initiatives with Canadian and Northern New England (especially New Hampshire) resources are not successful.

NU continues to work with Hydro Quebec and New England stakeholders to advance our suite of northern solutions projects. FERC approval of HVDC project structure was received in May 2009. NU is working to advance HVDC project with development of various agreements. NU is also working closely with New Hampshire legislators and their Transmission Committee.

9S Banks restrict access to short-term liquidity, resulting in higher fees and interest rates, shorter terms for our bank credit facilities, and more restrictive covenants, which significantly changes the costs and way we finance our businesses.

The bank market continues to strengthen. Although the pricing of revolving credit facilities has improved, the cost of these new facilities continues to be significantly higher than that of our existing facilities. Facility tenors have lengthened to up to 3 years, over the 364 day facilities that had been the norm earlier in 2009. Discussions are ongoing with current revolver banks over potential timing and structure of new facilities in 2010.

10S Major equipment failures or unplanned system repairs result in more expensive and/or suboptimal system repairs, and are used by public advocates to invoke regulatory proceedings and corrective actions.

Scheduled preventive maintenance was completed for all companies in full for 2009. The operating companies did not have any significant SAIDI or SAIFI issues in 2009.

11S Historical environmental remediation sites result in significant financial exposure to shareholders due to the lack of rate recovery.

NU is pursuing technical, political and legal strategies for addressing Massachusetts Department of Environmental Protection’s conditional approval of the Holyoke MGP remediation sites. A high level strategic meeting was held in January 2010 with MA DEP and key NU Personnel discussing policy-related matters. Technical meetings with the MA DEP are planned for February/March 2010 to evaluate next actions at the site. Periodic meetings are also being held with HG&E to share information on the site. Field delineation activities associated with the site have been ongoing in the Connecticut River since October 2008. Preliminary ecological risk studies and environmental forensics are ongoing on the tar/sediment.

12S Federal, regional and/or state policies create carbon constraints or other environmental regulations that are detrimental to our operations.

PSNH is continuing to implement a RGGI program by undertaking collaborative outreach with business groups, environmental organizations, the Consumer Advocate and PUC. PSNH is also evaluating various bills for potential impact to NU’s operations including bills under the Clean Air Act, Clean Water Act and Federal Climate bills.

Strategic Risk Momentum Summary – March 2010

Slightly Favorable

Slightly Favorable

Favorable

Neutral

Neutral

50

Beyond NEEWS, HQ Project, Significant Transmission

Investment Will Be Needed to Bring Renewables to Market

Connecticut

14% in 2010

27% by 2020

Vermont

Goal: 20% by 2017

Minimum: 2005-2012. Load growth to be met with renewables and capped at 10%.

Maine

33% in 2010

40% by 2017

New Hampshire

7.54% in 2010

23.8% by 2025

RI

4.5% in 2010

16% by 2019

Massachusetts

Class I Class II APS 5% in 2010; 1% annual 3.6% kwH sales 1.5% in 2010increments thereafter starting in 2009 & 5% by 2020

3.5% kwH salesfrom waste energystarting in 2009

Current New England Renewable Portfolio Requirements

51

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