Susan Allen – VP, IR & Treasurer Jim Torgerson – President & CEO Rich Nicholas – EVP & CFO

Christopher Ellinghaus – Wall Street Access Daniele Seitz – Seitz Research [ph]

Thank you, Russ, and good morning to everyone. Thank you for joining us to discuss the UIL Holdings second quarter 2008 earnings results.

Participating on the call with me today is Jim Torgerson, UIL’s President and Chief Executive Officer and Rich Nicholas, UIL’s Executive Vice President and Chief Financial Officer. If you do not already have a copy of our press release or presentation for today’s call they are available on our website at www.uil.com in the Investors section.

During today’s call we will make various forward-looking statements within the meaning of the Safe Harbor provision of the U.S. Private Securities Litigation Reform Act of 1995.

Significant factors that could cause results to differ from those anticipated are described in our earnings release and filings with the SEC. With that said, I will now turn the call over to Jim.

Thanks Sue and good morning everybody. Today I want to start with a quick overview of the earnings and then Rich will talk about the detail a little later.

But I also want to talk about our impending rate case. Some of the strategic initiatives we have gong on particularly related to our 10-year plan and some of the public policy issues that are surrounding the transmission business.

When we look at the quarter, we really had a very good quarter mainly because of the transmission business, which the earnings more than doubled in the quarter and actually year-to-date as well. That was mainly due to the fact that Middletown-Norwalk is progressing very well.

The construction work in progress has generated the earnings for that. And it goes to show that we are delivering on our plans and our commitments in completing that and as we said Middletown-to-Norwalk is more than 90% complete now.

The distribution was down almost 20% as a result of the sales being down about 5.2% on a weather-adjusted basis for the quarter. Year-to-date, they are down about 3.5%.

And this just goes to point out the need we have, which we are going to be asking for in our rate case for decoupling. Another thing that happened actually this week, we did receive our FERC order affirming our incentive rates for the Middletown-Norwalk project.

It was really our request for clarification that we wouldn’t need to have the Middletown-Norwalk in service by the end of 2008 [ph]. The FERC did affirm that and said no we did not have to have it in service and we still get our extra 100 basis points and the incentive rates we had asked for.

Now, on Page four, covered a couple of these things already. Distribution earnings are also being impacted a little bit by the capital spending we are doing.

We are doing a little more capital spending and obviously that increases somewhat depreciation and somewhat the interest expense. We are, however, managing our O&M cost very critically and if it weren’t for the uncollectibles being as up as much as they were, our O&M would be very close to what is currently allowed in rates for the – and it will be for the year.

So, the uncollectibles are really only the thing that’s driving our decision to file for rates. And on Page five of the presentation we talk a little bit about the rationale.

Obviously, we are not earning our allowed distribution return of 9.75%. In 2007, we did earn, and this combining the ROE for the CTA along with distribution, it was 8.93%.

We are forecasting now that that combined amount for 2008 will be in the 7.5% to 8% range. And when we look at some of the numbers that are used in setting the rates, kilowatt hour sales, and we have talked with you many times about this in the past.

We are seeing a trend of declining kilowatt hour sales where the – in 2006 it was down about three-tenths of a percent, 2007 eight-tenths of a percent. And this year, as we said already, we saw a decline of over 5% for the quarter and over 3% for the year so far.

The part is uncollectibles. What we had in rates, and this goes back to when the rates were set in – when we had the order in 2006, the beginning of 2006, we had $5.3 million of uncollectibles in rates, $4.2 million of that went to the distribution business, and a little – the balance was being collected in the system benefit charge, which is really kind of the social charges and for the write-offs of the uncollectibles related to the hardship customers.

That has gone up to where in 2007 the uncollectibles totaled almost $16 million and little under 10 were in rates. And we are projecting it to be over $20 million this year.

So, you can see that it’s a big issue. Now, we are – and have been able to move more to the system benefit charge.

We have a request pending in front of the Commission to move part of the uncollectibles to the generation service charge. We are awaiting an order on that.

All the briefing has been done and we are waiting for that to be occurred. And we were successful in moving some of the transmission – some of the uncollectibles to transmission.

So we are trying to get it aligned where the uncollectibles go along with all the components of the bill and not just be part of the distribution business. We are also seeing an increase in the distribution rate base.

So we are – again, we see a need for additional capital spending and we are going to talk about that with the 10-year plan when we hit that part of it. In May, we told you we were – we had a proposal to try to settle and come up with an alternative resolution to settle what we saw as the three drivers of why our distribution business was not reaching the allowed ROE that we thought we should be making.

And we had – those are the same three characteristics, the lower kilowatt hour sales, the uncollectibles, and the requirement to spend a little more on distribution business. We went through (inaudible) and tried to get a settlement which we did negotiate a settlement with the industrial customers, but then when we put forth to the Commission to expand the group to include the staff, the Commission elected not to proceed with the settlement discussions.

And so what we had proposed was really would have ended up a rate decrease for customers going to January 1st 2009 by moving the CTA extending that out and reducing that rate and increasing the distribution rate. But they didn’t want to do that.

They felt it was more appropriate to file a rate case. So we gave them notice on July 9th, two days after they terminated that docket, that we would be filing a rate – for rate increase.

On Page six, we have a chart that shows what we had said – the – at least the estimate at that time of what the rate increases would be and they are about 2.6% here. We are still finalizing that and there could be some minor changes to the numbers.

In the note we have, we said – it’s actually should be $6.7 million of the $33 million requested for 2009 represents revenues that were really previously approved by the DPUC. Rich can probably add some color to that when he gets to his discussions.

The decoupling of the revenues from the kilowatt hour sales is also something we are going to be requesting. This is actually required by the legislation that was passed in 2007 that says that all the utilities will request and the Commission has to consider decoupling mechanisms in order to eliminate any desires on behalf of the utilities not to pursue energy efficiency conservation methods.

We have been doing conservation for over 20 years, and for us it’s not a big consideration that we wouldn’t do it, but the decoupling mechanism is needed by us, as you can see, because of the decline in our sales. The timeline, we filed the notice of intent July 9th.

The earliest we can file then would be 30 days from that point, which would be this Friday, August 8th. And we have up to another 30 days to get it in.

Obviously, because of the shortfall in earnings, we will probably try to get that in as soon as we can, but it will be in the not too distant future. So, if you are looking for that we will have a decision.

The DPUC actually has 150 days plus they get a – well that characterizes an automatic 30-day extension. So you can figure, it’s probably going to be 180 days.

We have set up a page on our website. It’s a regulatory page and if you go to our – the UIL website and just click on the line that says Regulatory, we will be – there will be information related to the rate cases.

There are some there already. And you can keep track of what’s going on and we’ll make sure that keeps updated.

On Page seven, we start with the – what our capital expenditure plan is in the 10-year plan. Distribution and transmission now total about almost $2 billion, $1.97 billion.

Capital spending for this year are going to be about $193 million. As we said, the Middletown-Norwalk is moving very well.

It’s on track. Trumbull substation is complete and on line.

That was about a $25 million project. Again, and it also shows that we have been executing on our plan.

The Trumbull substation was one of the first initiatives in our plans that got put forth in our original 10-year plan. We had already been working on it.

But it’s just to show again – we are getting it done on time with – and pretty close to the budget that we established for that. On the next page, we have the detail of the 10-year plan.

Let me just go over a couple of things here. In the distribution area, we have added about $95 million to the distribution system over what you saw in the past.

Mainly this is related to – well, first off, we picked up 2017 and dropped off one year there so we have added a second substation in New Haven. That’s probably another – well for distribution is probably in the $12 million to $15 million range.

So we picked up some money there that we see we need in distribution and there is actually a whole list of a lot of different things we are adding. The support projects, and this is about $126 million over what we show in the last 10-year plan.

A lot of this related to things we are doing out in the field like field automation, outage management, a lot of it’s IT related, but IT related to the operations of the Company. Another big project is the remote disconnect.

This will allow us to actually disconnect and reconnect customers that are in hard to reach areas particularly apartment buildings, those that have a history of non-payment or sending crews out frequently to disconnect them, reconnect them. So this is going to save us on time and also on access too, which is probably even the more important.

And also for the safety of our employees because some of the customers aren’t as friendly as they used to be with our higher rates. Another area is the meter data management and a lot of the financial systems and our SA system.

So, we are going to be picking up some spending there. The transmission area is pretty much the same.

I mean again we picked up 2017, dropped off 2007 I guess and part of 2008, but it’s actually down just a little bit. What we did is we identified one of the unidentified substations.

We are putting in a second subsystem, as I said, in New Haven. So – and we pushed out one of the other ones, but that’s really only off about $7 million from what we previously showed you.

Another big thing we have put in and this is not it’s really in the 10-year plan but it’s in our request for – and our rate case, to add conservation and load management in the rate base, and actually spend money on it. We are proposing in the rate case, or we will be that we spend about $4.5 million in 2009 and another $18 million in 2010, and you can see the forecast we have going forward for what we think we could spend in conservation and load management to help our customers reduce their – the demand they have on our system.

And then – but we want to put it in the rates and then earn on it. And that’s the proposal we will be putting forth.

And we also have line for the GenConn where we believe we will spend our – put our $49 million in 2010 for the 200-megawatt project. We don’t have anything in here for a line item to access renewables.

And we are working with the policy makers and others on a renewable transmission line and you know and we have talked about this before that there are several proposals that are requests that were put into ISO New England to look at evaluating these lines. There have been policy issues that are starting to surface among the regulators in the different states, particularly Massachusetts and Connecticut who have the vast majority of the load they would probably need this, but they are looking at how do we meet the RPS standards?

How do we do it cost effectively. I don’t think people want to be looking at just putting in transmission lines and then accessing renewables in Canada and paying the marginal cost of natural gas plus an increased transmission charge in order to service that.

So we are trying to figure out who needs to pay for this and who is going to benefit, which are all very valid questions. So we will continue to work with the policy makers and make sure that the right answer comes through, which I think is what we – all need to be doing.

They also want to make sure that we are not just paying for really what – generation interconnects by extending long lead lines and calling them transmission. So I think there is a lot of policy issues that are going to need to be ironed out over the next year or so and along with the timeframe, when we get some analysis done by the ISO New England on what – which one of these makes sense.

So when you look at our capital spending, which is on Page nine, you can see distribution obviously, to summarize, we have identified some new projects, moved some timeframes around, and a lot of it’s timing changes. We have added some C&LM and the IT support projects and then transmission is basically still on plan.

When we look at Page 10, we have our average rate base, and you can see again it’s still growing, probably growing even a little faster than we had before mainly because of distribution is up a little bit over what we had in the past. Transmission is still growing nicely at 20% compound annual growth rate.

If we went back to 2006, we only had a $100 million, so by the end of this year we are more than tripled the amount we have in transmission. What we can see yield will be up to about $1.4 by 2013.

Moving onto Page 11 where we have our peaking generation. As I think all of you are aware, we were awarded 200 megawatts along with our partner NRG to build peaking generation in the state.

The other parties that are going to be building peaking generation are Bridgeport Energy II, which is a partnership with Dynegy and LS Power, and PSEG. The timeframes when all those will be on line, our is planned to be on in June 2010.

And on Page 12, we have a little more detail about that. I think as most of you are aware, this peaking generation for all of the participants will be on a cost-of-service basis and we utilize a contract for differences.

That just means that the owners of the generation will be having a contract with the utilities to provide the payment mechanisms and then we obviously would pass whatever we have to get through to our customers and collect it that way. The contracts for differences really comes about between what the customers would pay and what has gotten or received in the marketplace either through the forward capacity market, the forward reserve market, or by selling energy.

And then it’s – there is a calculation as to what each entity would get. In our case, we had proposed a 10.25% ROE with a 50:50 debt structure and the O&M that goes along with that.

That generates the revenue requirement we need for our GenConn project. And if the market revenues are greater or lesser then it gets adjusted through payment by customers.

So, that’s the definition really of that contract for differences. The project is being supported at a financial level by project financing.

That’s why you see although we have about $200 million project we will be putting in $49 million or about a quarter of that. All of the debt, the 50% debt is done at the project level.

We have arranged for an equity bridge loan, so we really don’t have to put in equity until the – it goes to commercial operations. Having said that though because of the timeframe to get the financing in place, we will probably be funding [ph] a little bit of the money until we get it closed in the fourth quarter or worse the first quarter.

We have already signed the contract for differences. That was done August 4th.

We are going to be placing the orders for the longer lead time items, the turbines mainly, which will be done this month or into September. Engineering completed and designed and construction contracts can be awarded by the first quarter of 2009.

And we’ll be done and operational by June of 2010. And we are also exploring maybe some other opportunities for generation in the state with our partner NRG.

And with those comments, I would like to turn it over to Rich who can go over the financial results.

Thank you, Jim. Good morning everyone.

Thank you for joining us today. Just spend a little time discussing the second quarter results and the six months year-to-date and then review our outlook for the rest of 2008 for the year in total.

On Slides 13 and 14 of the presentation, as you can see net income from continuing operations was up second quarter by $1.8 million or 19%. And for the full six months year-to-date, net income from continuing operation was up $2.9 million or 16%.

So very good growth year-over-year and quarter-over-quarter, as Jim mentioned, primarily driven by the transmission growth. We benefited from the growth in the rate base from Middletown-Norwalk, Trumbull just went in, in June, so a small effect there, but we will see that for the rest of the year.

And FERC’s decision earlier this year that increased the transmission return on equity by 20 basis points. Looking at the transmission net income, more than doubled, up 114% second quarter over second quarter of $3.3 million and about the same percent six months over six months.

Given the FERC decision and the current forecast of transmission rate base, we currently are estimating the rate of return for the year to be right around 12.5% on transmission. On the distribution side, net income was down $1.4 million quarter-over-quarter, about 20%, really driven by the decrease in kilowatt hour sales of 3.5% on actual sales.

Year-to-date, actual sales are down about 3.4%. We were helped a bit in the second quarter by the weather.

There were 52 more cooling degree days in the second quarter of ’08 compared to 2007. And while there were other variances within the quarter, they basically offset and the earnings decline really is attributable to the decline in kilowatt hour.

Interestingly, although our uncollectibles in total were up in the quarter, there was no bottom line impact because the increase was due hardship customers. And in Connecticut we have a structure where uncollectibles related to hardship customers are transferred to the systems benefit charge for pass-through recovery.

So amounts did not hit the bottom line in terms of the variance in the second quarter. Corporate costs were off slightly primarily due to lower interest income on short-term investments as we redeployed cash from the Holding Company into the utility to support the CapEx program.

I would also note that in the quarter we successfully priced and closed just recently $150 million of long-term debt. $50 million of it is new long-term debt and $100 million is for refinancing.

We will fund those in the fourth quarter when the long-term debt comes due and the need is there for the additional $50 million. I would note that there was significant interest in our private placement and the process worked very smoothly.

One other item on the rate case, as Jim mentioned, when you look at the notice of intent and our request for $33 million in 2009, you may recall that our last rate case was a four-year plan and we actually had a rate increase scheduled to go into effect January 1, 2009, of $6.7 million resulting from that case. And so the incremental dollars over and above that are about $26 million to get to the $33 million.

The way the DPUC regulations work when we file our notice, we have to compare it to now current rates, which obviously don’t have that January 1 increase in them. Now, moving to Slides 15 and 16, let’s take a minute to talk about the outlook for the rest of 2008 and the year in total.

As you noted in the release, we have reaffirmed our overall guidance for continuing operations of $1.82 to $2.02, although certain components have been revised. We have increased the transmission guidance to $0.88 to $0.92 a share from what had previously been $0.80 to $0.84, reflecting the growth in rate base and the higher ROE.

Distribution guidance has been reduced to $1.00 to $1.20 from previously $1.06 to $1.26 a share, reflecting the impact of the kilowatt hour sales and uncollectibles, which we are not projecting to result in a distribution plus CTA rate of return of about 7.5% to 8% for the year in total. As you know, summer weather can be a significant variable in our business, and therefore we anticipate tightening the guidance range with results.

One other item as we look at our equity needs moving forward, now that we know the amount of the GenConn award and the timing of that, we do expect to issue equity prior to the GenConn in-service date of June 2010. In addition, the outcome of the rate case and the ultimate allowed regulatory capital structure as well as overall market conditions will affect the timing and amount of equity that’s required.

We do anticipate after the rate case decision that we will refine our expectations in this area. So, I will now turn the call back to our coordinator Russ for questions and answers.

Hi everybody, how are you.

Hi, Chris, how are you doing?

Good morning.

Good. Good morning.

Can you talk a little bit, Rich, maybe about the kilowatt hour sales and the discrepancy between nominal sales and weather adjusted number and what are you attributing that to, is it economy, is it conservation, what are your thoughts there?

Yeah, it’s all of the above. Weather adjusted sales for the quarter were off just over 5% even thought the actual sales were 3.5.

We are clearly seeing customers take action on conservation. They are not only getting squeezed by electric price (inaudible) $4 a gallon for gas, concerns about home heating oil, grocery prices are up.

So we are seeing folks really take affirmative steps to reduce their consumption.

Okay. Can you also, given your sort of raised the expectations for the ROE this year, maybe just the FERC adjustment relative to you prior expectations.

Where do you see the transmission ROE sort of terminating out towards the end of the plan?

Towards the end of which plan, Chris?

Say, 2016. Where will the ROE end up do you think?

We haven’t publicly put those kind of projections out there, but right now our rate base is dominated by Middletown-Norwalk, which has all of the incentives in it. Once that goes in service and starts to depreciate and we add other capital that may or may not have incentives as we apply it FERC, we will probably see some shift over time.

Okay. And in terms of the updated CapEx, are there any projects that (inaudible) for some of the latter changes?

Yeah, Chris, this is Jim. Not really, there is – we added a little bit more definition on some substations, which were in the plan but as – to be determined.

Right.

We even shifted some things around but for transmission it’s really not much of a change. Distribution, we saw some more things we needed to do and along with IT projects.

So really more of the capital is going into distribution and to other projects which are really IT related for operations. So the biggest one that you can probably look at would be remote disconnect.

That’s a – that’s a fairly significant project depending on how much we end up doing. And that’s going to over several years.

I mean it’s going in and replacing meters basically or adding a device to the meter that allow you to do the remote disconnect. So, that takes a little time.

So it will be over a probably a three-four year period. Be my guest.

But nothing that’s going to leap out and say – it’s a lot of little things. It’s not – there isn’t one big thing you could point to.

Okay. Can you, Jim, can you give us a little bit more color on what the responses look like to the Canadian transmission projects?

Really hasn’t been much yet. I mean we are starting to see stuff from regulators to say we ought to make sure who is going to be paying for this, how it gets done, that there isn’t a lot of this generator interconnects that are being characterized as transmission when we are trying to access the renewables.

I think everybody is in favor or accessing renewable, recognizing we got the renewable portfolio standard. ISO New England now, as a result of the request to do these studies, is going about doing (inaudible) and I think there is going to be more collaboration among all the parties over the next year plus to see how this all works out and what is needed, what’s the most cost effective way to do it and in their minds who is going to pay for it.

Okay. All right.

Well thanks so much and thanks for the CapEx update.

Okay, Chris.

Talk to you later.

Hi. I just wonder I mean –

Hi, Daniele.

Hello. I – what do you see for next year in terms of kilowatt hour sales and do you see a lot of that – most of the low-hanging fruits for conservation are out this year and next year we will be – it seems a bit more, but I mean most of it is already out or do you think that it could be of the same magnitude?

I don’t know the magnitude, Daniele, I would expect –

Again, your feeling from the effectiveness of the programs, et cetera.

I think the programs are proving to be effective. We are also seeing that there is probably more that could be done.

We are proposing two things. We are going to propose two things in the rate case.

One is decoupling. We are not harmed by it.

And secondly, the – putting a conservation and load management spending in the rate base. We still see things perhaps some distributed generation that could occur.

More conservation in homes. I think a lot of people still have ways to go on what they can do from an energy efficiency standpoint.

And I think – so we should see some more of that. We are also seeing people are using electricity a lot more though and the idea to use it more efficiently.

So, where the bottom is in this I am not quite sure yet. How long is it going to take before it stops declining, but I do – I would expect that we are going to see some probably some continuation in decline in sales would be my guess.

How much I don’t know yet. I mean those are some of the things we are working on.

We’ll have some projections when we do our rate case but since we haven’t filed that yet I am a little loath to go and discuss it.

I was also wondering –

We will see that in a very short period of time when we put out –

Yes. When you are talking about decoupling, does that mean that any kind of a measurable reduction in demand that will be seen over a – annual period with the (inaudible) on the manual basis, is that the way you see working without you having to file for other rate increases?

Is that how it works?

Yeah, what we are looking at Daniele, would be a mechanism that would true up to the revenue requirement.

Okay.

And identify the revenue requirement on an annual basis, which we were going to do in our rate case, and then to the extent the sales don’t generate that or generate more, one way or another, then you do a true up in the following year. So we want to make it a very simple mechanism, so you just go back to the commission and say if your revenue requirement was $1 billion and we got $980 million we need to true up to $20 million the next year to make it really straight forward.

And this will go through without rate cases or anything like it, (inaudible)

Yeah, that’s the way I would – that’s really what we are suggesting. Now, what the Commission does is – we’ll see, but that’s what we are suggesting.

Are we going to be–

And in terms of following on the previous question, in terms of the decision for additional transmission expenditures, this will be made or requested by the ISO and you do not anticipate this to have any impact on CapEx in the next year or two?

No, I don’t see it in the next year for sure. If they say go ahead and we are one of the ones doing it, we may have to start spending a little money, I don’t know, Rich, maybe 2009, maybe you know on exploratory work, sighting, that kind of stuff.

But it will probably the latter part of them. And yeah, my guess is there are going to be people partnering on this.

So, it also depends on how much you are going to spend –

Right, right.

And not present (inaudible) on how you finance it and organize it. So –

This is transmission coming from Canada or will it be transfer [ph] along all of the renewable – the potential renewable resources across the ISO?

Probably a combination. I think most of the renewable resources that are in New England are up in Maine and a few other spots and mainly it’s in the northern part of Maine and in the southern – and in Canada.

But that’s where I think most of these transmission projects are pointing towards.

Okay. And as far as your rate case, you ask for (inaudible)

We haven’t filed it yet, so we haven’t –

Oh, so there is no specific number yet?

Not yet. Like I said we will be filing it pretty soon.

So just watch our web – we will let you know –

No, my mistake, yes I chose a number and I thought it was associated to a certain ROE. So the $33 million number is not to do with distance between the previously allowed ROE and the one you are anticipating for ’09, is that how it works?

There is a piece of that in there, yes –

Okay. And the recovery of the collectible – the uncollectible, will that be done over a certain number of years I mean you leave it up to the Commission?

I would be – this is Rich – it would be the current recovery of the expected 2009 and 2010 on the collectibles – wouldn’t provide for any recovery of prior write-offs.

Okay. Okay.

Great, thank you so much. Appreciate your help.

Thanks Daniele.

Okay, well thank you all very much. We appreciate your participation and if you do have further questions, obviously give us a call and Susan Allen will be happy and Michelle will be happy to help you out.

And have a good day. Thank you.

Thank you all.

Thanks everyone.