Susan E. Allen – Treasurer & Vice President-Investor Relations James P. Torgerson – President & Chief Executive Officer Richard J. Nicholas – Chief Financial Officer & Executive Vice President

Dan Fidell – U.S. Capital Advisors Brian Russo – Ladenburg Thalmann Andrew Weisel – Macquarie Capital Securities Chris Ellinghaus – Williams Capital David Paz – Wolfe Research Robert Howard – Prospect Partners Andrew Weisel – Macquarie Capital Securities

Good morning. Welcome to the UIL Holdings Second Quarter 2013 Earnings Conference Call. At this time, Susan Allen. Susan E. Allen: Thank you, Maggie, and good morning to everyone. Thank you for joining us to discuss UIL Holdings’ second quarter 2013 earnings results. I’m Susan Allen, Vice President of Investor Relations. 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. During today’s call, we will make various forward-looking statements within the meaning of the Safe Harbor provisions 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 the filings with the SEC. With that said, I will now turn the call over to Jim. James P. Torgerson: Thanks, Sue, and good morning, everybody. The second quarter for 2013 turned out to be a very good quarter for us. All of our subsidiaries reported improved financial results in the second quarter and year-to-date for that matter compared to the same periods in 2012. The improvements were largely a result of returning to more near normal weather wasn’t exactly normal, but it was pretty close. We have a larger base for the transmission of rate base and the impact of our natural gas conversions has been a plus. So for the second quarter in 2013, we had net income of $17.9 million that was an increase of almost $6 million or were up 49% compared to the second quarter of 2012. Diluted earnings per share were up $0.12 as well. Year-to-date net income was $69.7 million that was an increase of $10.7 million or an 18% increase. And again diluted earnings per share were up $0.20. Also we are reaffirming our guidance and that excludes any impacts on purest final order on our electric distribution rate case which Rich is going to talk about. Now when we hit the Page 4 on the electric distribution rate case, we thought we would go through the draft decision that the commission came out with on July 30. There the draft decision that the authority had was revenue of $21 million for the first year and $16 million for the second year versus but we have requested which was $65 million from the first year and $26 million in the second. They had a 9.15% ROE and a 50-50 debt-to-capital structure, and would continue the existing decoupling mechanism also recognizing that they plan on having a generic docket on de-coupling, now one things that I want to acknowledge in the draft decision and it is a draft this is just all part of the process. They have actually a higher sales forecast than what we had in our request and with de-coupling should it turn out that our forecast is the one that actually end up being the fact in the future, but had about $5 million in revenues in the first year and now is $3 million in the second year. Assuming our forecast is the one that proves to be the accurate one. They had recovery of above $37 million of strong related cost over 10-years with the 100% debt carrying charges. A continuation of the earnings sharing mechanism of 50/50 and using the customer’s portion assuming we do have a sharing recognition that would then be applied against the strong regulatory asset. Capital spending for the 2013 to 2015 timeframe would be around $450 million compared to what we’ve said previously in our Investor Call of about 4.4 and actually it doesn’t change a whole lot in those first few years. That still includes the amount for the enhanced tree trimming, which we talked about. The written exceptions we filed yesterday, addresses a lot of aspects of the draft decision coupled in particularly are The United Illuminating to operation administrative center valid entail a write-off of about $21 million if the draft becomes the final and storm related cost, get out to expenses about $16 million and that we have is a regulatory asset currently. There is issue on the corporate capital charge, which is more timing and a regulatory lag issue for us. Return on equity [9.15] obviously is an improvement over the 8.75 when we are out it is less than what had asked for. The enhanced tree trimming although they did acknowledged that we should do it they would only give us debt cost on that which we don’t believe it is appropriate for a capital program. And then there some issues on carrying charge. And as I mentioned sales forecast it is different than what have our requested are there is a little higher than ours. The remaining timeline all arguments going to be Monday the 12th from the final decision is currently schedule for the 14th. On the next page we have some other regulatory updates the renewable connections program this is the renewal of we’re a lot of built up to 10 megawatts renewable energy generation in our service territory and have it as basically cost of service mechanism. We have reached an agreement and the principle with the prosecutorial staff of the authority, and we are expecting to file that PURA for approval what it would entail is this there is a mechanism that will allow as an ROE that would be a greater of an ROE 25 basis point above the UI electric distribution ROE or 25 basis points less than the CLNP ROE and then there is target equivalent market revenues which equates to additional 25 basis point. So in the end it is about the 50 basis points increase in the ROE over what today would be the UI electric distribution ROE. So assuming the 9.15 is one ends up in the final we would add about 50 basis points so that to be 9.65 to file that with PURA very shortly. The investigation in the Storm Sandy is the draft decision came out the same day, and the UI electric distribution case draft, and PURA found that the local distribution companies did perform their storm related activities at a timely and effective manner. They had some suggestions for improvement, which should be normal. Ours were mainly around communications and making sure on the estimated restoration times, we got those audits quickly as possible and accelerated our ability to do this. The final decision is expected later this month. On the comprehensive energy strategy, Connecticut companies jointly filed – and this will be Yankee Gas; along with our companies Connecticut Natural Gas and Southern Connecticut Gas. We filed the plan with the Department of Energy and Environmental Protection, and also with the Public Utilities Regulatory Authority. And it outlines how the gas companies would connect customers to natural gas. Now, look for the structure to add above 280,000 new gas heating customers state-wide over the next 10 years, and of that 280,000 nearly 200,000 would be for Southern Connecticut Natural Gas, our companies. Just to provide more flexibility in the process of adding customers to keep the cost of the utility hookup to the customer down. And as we mentioned in the past there are number of mechanisms that we’re suggesting that actually were in the Comprehensive Energy Strategy. This pooling of requests, 25 year or look at on a net present value basis to determine the contribution in aid of construction if there should be one. Putting in a new customer rate that would help offset any customer charges for expansion remains. Our proposal is that it would be applied only to expansion new customer rate, but only be applied to those customers who have a main extension though. Using off systems and sales and capacity release, revenues to help mitigate the cost for adding new customers on main and off main and then on-bill financing – and a slightly new twist was a furnace bill that passed through the legislature would allow on the electric bill to have customers switch to natural gas and then over up to a ten year period be able to finance on their bill at relatively low interest rate of around 3%. So that’s been gone to the legislature and that’s been discussed right now deep in PURA. So a decision on this is expected in November of this year. Moving on, we filed our Connecticut Natural Gas, a rate case on July 8. The rate reliefs needed there as to recover the past and future capital expenditures that are making or will make and also to support the availability of gas consistent with the Comprehensive Energy Strategy. And we also need to look at the return on equity. One other thing we're focused on is the normalized use per customer, which as we’ve said in the past, there’s the declining, and it’s one of the reasons we’re not generating the revenue that we need. The highlights of that request, the test year is 2012, we’ve asked for $19.9 million that would be for the one year period in 2014 and that 6.6% above the projected revenues now under existing rates schedules. We asked for 10.25% return on equity just about 52.5% equity in the capital structure and about 47.5% with preferred and long-term debt, which is the current allowed ROE is 9.42% and the capital structure the same. We also asked for a decoupling mechanism on revenue for customer base. This would allow us then to have decouplings, but then to also retain growth from new customers, which would be very important. We also asked for a tracking mechanism, so we can timely recover the proposed accelerated cast iron and bare steel replacement program that we put into the request. And we’re expecting a decision from PURA, either late in the fourth quarter or early in the first quarter of 2014, if they take the allowed six months it would be in the early part of January. As far as gas conversion, this is a real plus. During the end of the second quarter we had converted 7,749 households to gas. That’s already 64% of the target of 12,200 we had for this year. In July, we had another – a little over 13,000, so we’ve converted a little over 9,000 homes and businesses to gas through July of 2013. We’re well on our way to meeting the target we had set up, two and half years ago, we would hit 30,000 to 35,000 and you can see from the past, we’re actually exceeding what we did in 2011 already through July. And we should exceed the target we have this year of 12,200. We’re looking at again, 2014 to 2015 timeframe we are doing about 55,000 conversions of natural gas and our target for next year for 2014 is 15,315. Gas sales, you can look at the chart, you can see that the normalized usage per customer has come somewhat. It’s reflected in the margin, we’ve seen in the quarter and also year-to-date. For the quarter we were actually up a little over $1 million and for the year-to-date $2 million, which added about $0.03 a share as a result of the improvement. Still not to where it was when the last rate case was decided, but it has improved a little bit. So I think our observation that the abnormally warm weather in 2012 distorted that use per customer and we’re seeing it move back up. Now there’s some news on the FERC ROE complaint, I think most of you are aware that the Judge [Cianci] issued his initial decision yesterday. And to give you the history, there was a 206 complaint filed at FERC by governmental entities in New England that said the 11.14% base for the transmission rate base was not just in reasonable. But the judge's initial decision that yesterday was that for the refund period, which would go from October 1 of 2011 through the end of December in 2012, the return on equity would be 10.6%. Going forward and this would be whenever FERC actually decide, which is probably not going to be to sometime until 2014 March, April timeframe hopefully that are the 9.7%. But you also have to realize that historically, FERC has modified that number to reflect changes in interest rate from the time they had done the analysis. So this would be April of 2013 and it’s six months prior to that they usually look at, and then they takes the six months timeframe up and to when they issue an order and reflect that in the ROE. This is what they’ve done in the past. So if you look at it today, we probably add about 80 basis points, 9.7%. So if you look at something around 10.5% in FERC does that and they will ultimately decide looking at the judge's initial decision and then either adopting it, modifying it or changing it entirely. But usually we see where it ends up. Now the other thing that is important to note is the adders that we have on ROEs that we’ve been granted in the past still do apply and in some cases the 100 basis points, some 150, some even higher 200 basis points for part of our Middletown-Norwalk project, and those are declining overtime. So I’ll turn it over to Rich, and he can go through the financial results. Richard J. Nicholas: Thank you, Jim. Good morning everyone I'm on slide 11 in the deck, where we’ve laid out the segment results of net income and earnings per share for the quarter and year-to-date and on slide 12 the narrative begins around that. As Jim mentioned a very solid quarter of up 49% compared to second quarter of 2012 and year-to-date were up 18% compared to 2012. Looking at the individual segments, in the electric distribution area which also includes the CPA earnings as well as GenConn up $1.2 million for the quarter compared to the same quarter last year of 11% and year-to-date we’re up $1.5 million in net income or 6% more, both of those primarily driven to an increase in rate base and as a result as the rate base has grown we do not have any earnings sharing recorded in 2013, which we did have in 2012, but GenConn was essentially flat down about $100,000 quarter-over-quarter due to a non-recurring adjustment that happened in 2012. Further rolling 12 months ended June 30; the average return on equity for distribution including CPA was 10%. Moving to Slide 13 in the Electric Transmission segment of our business $1.1 million increase in net income quarter-over-quarter, which is a 14% growth and looking year-to-date $2.4 million increase in net income or 16%. Again, both of those driven primarily by increases in rate base as well as allowance for funds used during construction, our construction work in process and our investment in the NEEWS project the pre-tax income was up about $200,000 year-to-date as compared to 2012. The weighted average of our transmission ROE including incentives as Jim mentioned was 12.3% for the 12 months ending June 30. Now turning to our gas distribution business, as you know the seasonality of the second quarter is typically not a strong quarter, but compared to the second quarter of last year, the loss was reduced substantially and the improved results there were primarily due to the colder temperatures as Jim mentioned, and while they were near normal, they were significantly colder than what we experienced in 2012. And some of that was partially offset by an increase in O&M expenses. Moving to Slide 14 on the year-to-date, up 21% and $5.4 million of net income increase, again primarily driven by the weather, and as you can see we’re closed to normal for the quarter, actually note quite a percent over the normal and for the full year so far, a little bit warmer of 1.7%, warmer than normal, but significantly colder again 34% colder for the quarter and 24% colder on a year-to-date. On Slide 15, we summarize there that the major drivers of the change in the gas business for us and as you can see for the quarter, weather was $0.06 of share out of the $0.09 variance, a little pickup in the normalized used for customers and the conversion the customer growth added $0.02 for the quarter-over-quarter comparison. But year-to-date $0.17 coming off the normal weather for us, $0.03 on normalized used for customers and again the benefit from the customer growth almost $0.04 there. Overall the average ROEs for the period ending June 30, SCG about in the 6% range CNG approaching 8%, both regularly and weather normalizes. On the Corporate segment where we do maintain some interest costs and capital that serves all of our utilities, the loss was a little bit less there quarter-over-quarter and year-to-date, primarily due to a tax benefit we’ve picked up by doing a unitary tax filing for Massachusetts state income tax. Moving to Slide 15, again reaffirming our 2013 earnings guidance of $2.05 to $2.25, important to note that it does not include any potential impacts from the ultimately be the final decision in UI’s electric distribution rate case. Should there ultimately be some write-offs there that would be non-recurring and to the extent there are major changes in the draft decision and we would certainly be out with information on that shortly thereafter. On the transmission business, embedded in the guidance is that we will earn our allowed return there, then it looks like any changes coming out of the initial decision from the ALJ would not occur until 2014. We have factored a normal weather for the rest of the year. As we discussed earlier this year, we did see pension cost to go up this year as the discount rates were very low at the year-end and that’s been factored in. As well as the ultimate amortization of our CTA rate base by the end of 2013 that rate base will be fully amortized and we will not have any CTA earnings going forward past that. Here we’re picking up the earnings on the natural gas conversions. So with that, I will now hand it back to our operator Nicky to start off the Q&A session.

(Operator Instructions) Our first question comes from the line of Dan Fidell with U.S. Capital Advisors. Your line is live. Dan Fidell – U.S. Capital Advisors: Thanks good morning. James P. Torgerson: Hi, Dan. Dan Fidell – U.S. Capital Advisors: Just a couple of questions on my side I guess first can you talk a little bit about the gas conversion target I know 2014 to 2016 about 55,000 new adds in the projection. How could that target move if we get any kind of change at all based on the CES plan? James P. Torgerson: Dan I think we had – when we did that estimate we assumed we were going to get much of what is in the CES plans. So it’s pretty consistent with that and we were anticipating the 55,000 maybe if you think about it we have 15,000 in 2014, SMEs we are going to be doing 20,000 a year, the next two years. So that’s starting to get where we need to be and if we look at the target of doing almost 200,000 in 10 years that’s pretty much on track and so I think that’s about where we expected to be. Dan Fidell – U.S. Capital Advisors: Okay and I guess, just a follow on to that question. is that – that kind of top number that we can assume just sort of maximum in terms of what you’re able to do, not just sort of CapEx wise but also just in terms of skill set, labor ability of crews, and to be put on as well? James P. Torgerson: I wouldn’t say that it’s the top end. I think we had some challenges getting more crews and getting the people certified to be able to, put the pipe in the ground and then also having, and this is a contract appears, but then also the HVAC dealers to step up to be able to have the customers, but I think as things keep growing that number to go a little – can go higher, how higher is up? I don’t have a quite a feel for yet. We are hitting we are actually doing pretty well at the moment, but there are some constraints where we start running into and we’re out there working with the contractors and for both those who the put the pipe in ground and those HVAC dealers. So, I think it could go be more than that. Dan Fidell – U.S. Capital Advisors: Great, maybe just a separate question, just interested in your take on the FERC ALJ recommendation, you did a good job of sort of mentioning about the markup on interest rates and between periods and getting closer to that, kind of 10.5%. ROE all in based on today, but if interest rates rise further between now and sort of early to mid-2014 when FERC finally orders, it could be even closer to 11%. I’m just kind of interested if you be one at a time and then what you think FERC may ultimately do for kind of that close to the spread James P. Torgerson: Good question. I’m not sure of the answer. We probably have a difference FERC but certainly have a different Chairman when it become time for that order. I’m nor sure, I no what going to do at this point. I think they are going look very seriously at the judges initial decision and go from there I think finding that the 11.14% was unjust and unreasonable, which he did say, it’s kind of hard assume that they’re going to get a number at that level. But I think if you look at the 10.5% or something that ballpark, that’s not unreasonable based on what we’ve been thinking so. Dan Fidell – U.S. Capital Advisors: Okay, great. Thanks. Last question for me just in terms of the gas rate case, can you just sort of mentioned it all about sort of how that was received initially? I think certainly asking for just some basics throughout the structure to get a opportunity to earn the ROE a little bit better, a decoupling pipe tracker? How has that been received, I guess just initially? James P. Torgerson: Haven’t gotten much reaction, we’ve gotten 400 data requests and interrogatories. So there hasn’t been much reaction from either the Commission or anyone else at this point. I think most people understand that the use per customer is down, and that needs to be corrected. And that's probably the biggest part of the case, when you really look at it. And actually there hasn't even been any publicity on it, haven’t seen anything on it. Now I’ll give credit to our communications people for work on that one. Dan Fidell – U.S. Capital Advisors: Just I would assume with the supportiveness in the CES of expansion, I know gas across the state, but that might be a supportive case to that they would ultimately be supportive of your request in that case and just final question from me and I’ll step back with someone else to ask question. But how might that impact a follow-on filing for SCG behind CNG? James P. Torgerson: We’ll keep looking at SCG, but right now our projections are that SCG is going to be in the right ballpark as far as ROE. It would be more looking to the future, we get things like decoupling and that we want to look a rate case, but right now our plan aren’t to follow up immediately with a need right at the moment but keep monitoring it. Obviously we wanted to get decoupling for both companies at some point so just keep monitoring it.

Okay. Our next question comes from the line of Brian Russo with Ladenburg Thalmann. Your line is live. Brian Russo – Ladenburg Thalmann: Hi, good morning. James P. Torgerson: Good morning, Brian. Brian Russo – Ladenburg Thalmann: With the draft decision out on the UI general rate case a few weeks ago in yesterday's written exceptions can you just comment or elaborate on the differences in rate base from what you filed and what was included in the draft decision? James P. Torgerson: Yeah, the rate base wasn't dramatically different I mean the couple of items one the UI administrative office building, its still got about $21 million there. The longer-term on our transition and distribution operational excellence initiative they still got some money mainly in the later years that they want to see as to your benefit analysis and just justify those future expenditures. So that was reduced, Rich you could know that I'm running that and… Richard J. Nicholas: No it wasn't significant, and if you were to add back in this renewable connections project that Jim talked about earlier and that's going to add $40 million or so to rate base equivalent over time would really see that in-service for a year or so yet. James P. Torgerson: The other thing we had mentioned the enhance (Inaudible) that's about starting in 2014 it's about $25 million a year it's about a $100 million project over a four year time they have included that but the only issue we had that we could run costs down and that thus is not quite acceptable; I mean, can’t be putting out $100 million over four years and not earning our cost of capital on that. But really the differences in rate base are actually fairly small, and then when you add in its rest of the Renewable Connections program, it basically gets the zones back to where we were, with what we had told at the street at the prior timeframes. Brian Russo – Ladenburg Thalmann: Okay, maybe you could just elaborate on the Renewable Connection opportunity, I think, previously you were not going to invest in that, because of the less than constructive ROE, but now it seems that you concluded that in your rate base and... James P. Torgerson: No we – okay let me talk, we have not included it in any rate base forecast you have. What I said was that we reached an agreement with a prosecutorial staff, an agreement in principle that it would be UI Electric Distribution ROE plus 25 basis points added to that and then another 25 basis points added from our market revenue back. So we would really be adding 50 basis points above UI’s ROE or it’s actually greater of that or stay on fee return on equity minus 25 basis points, plus the market in revenue, so basically (inaudible) ROE. So it’s the higher of the two, so right now it would be looking if the 915 is the one that stays, if you look at it about 9.65 return on equity which is we feel reasonable for this type of project. And so we will be petitioning commission to go forward with that and with that settlement discussion we’ve had with the prosecutorial staff. So it's actually much better than the 875 that they initially came out with.

Our next question on the line is from Andrew Weisel with Macquarie Capital. Your line is live. Andrew Weisel – Macquarie Capital Securities: Thanks good morning guys. If I could follow up a couple more questions on that draft decision. First if you could elaborate a little bit may be describe where they disconnected on the Central facility between what you had requested and the draft decision and then second on tree trimming why do you consider this to be a capital investment when most of your facilities lump that into operating expenses? James P. Torgerson: Now let’s take the tree trimming first. While we had request – and you’re right, it is normally it is an operating expenses and we had suggested as an alternative that we would spend nearly a $100 million over four years to do what we characterize as a blue sky tree trimming which is to go and clear cut areas around the lines make a larger envelope which would help the reliability and put it on the lines themselves as a capital expenditure. That was a concept, which they have done for Connecticut Light and Power. They have a lot of that in the past. In order to make a very quick move into removing a lot of tree limbs that surround the lines today, they help with the reliability and help them storm restoration. So the idea was to do something very dramatic and quickly over a relatively short period of time. Normally you’re right is the tree trimming is an operating expense in the past, we spend about $4.5 million or $5 million a year on tree trimming which has been in rates. ROE – was the draft came out with that it only allowed us to get our cost of debt on that $100 million capital expenditure. But what we suggested in our written exceptions was that either they provide us with the cost of money include equity or put it all into rates as an O&M expense or we go back to doing what we had in the past $85 million of rate on O&M expense and then not have the dramatic improvement in the tree trimming. Andrew Weisel – Macquarie Capital Securities: And there is significant president from various decisions over the years from the DPUC what’s now PURA that allows at full cost of capital on various times of expenditures? James P. Torgerson: And on the UI administrative and office and operations center, they said that $21 million shouldn’t be allow, they broke it down in the two areas. One was the cost of land. They said it was higher than what we had said when we initially put the project forward to them back in 2005 on a conceptual basis and we had about $5.8 million for land cost at the time of estimate. We updated that in 2008 case to reflect the land that we were actually purchasing which was about $21 million, and they objected to the fact that there was fractured bedrock, and which we had to deal with by putting filings and it really was more than what they anticipated, they took about half of that of $12.5 million and there was another $8 million they took out if said then really approved, which it had by a more, so there was some disagreement on that piece of it. So that’s what really went just for the $21 million on the license. Even though and we didn’t have an improvement in the benefit, we demonstrated the benefits over the status quo would have been about $31 million present value benefit to customers over the present value basis over the [20] years.

Hey your next question is from Chris Ellinghaus with Williams Capital. Your line is live. Chris Ellinghaus – Williams Capital: Hey good morning guys. James P. Torgerson: Hi Chris. Richard J. Nicholas: Good morning. Chris Ellinghaus – Williams Capital: Can you put any numbers on the renewals connection, how meaningful that might be? Richard J. Nicholas: That is roughly $40 million capital investment. Chris Ellinghaus – Williams Capital: Okay, great. Richard J. Nicholas: And it’s basically cost to service. I mean the way to look at it and be a little over – with the numbers that we’re in the draft decision at the end of being about a 9.65% return on equity. Chris Ellinghaus – Williams Capital: Okay. Rich, you were talking about tax benefit at the parent level. Can you put a number on that? Richard J. Nicholas: Hey it was roughly a $0.01 a share benefits from being able to take advantage of that. Chris Ellinghaus – Williams Capital: Okay, and did the FERC ALJ say anything about address the contention of the utilities that this might impact the motivation sort of the chilling effect argument. Did you address at it all? Richard J. Nicholas: What he did Chris, let’s say that he was looking at the numbers specifically and addressing the numbers and using the DCF Analysis and looking at the arguments there, and he would let the commission decide on policy issues, but that’s really what he said, so he didn’t go there. Chris Ellinghaus – Williams Capital: That makes sense. Rich. I’m just looking at the trailing 12 month earnings numbers is definitely starting to push the upper end of the range. Can you just talk about what the third and fourth quarter look like weather wise and what kind of weather benefits or drags there might have been, that might impact our thinking on the second half of the year? James P. Torgerson: So, obviously we’ve got big data return to normal weather after to go back to – to releases from last year. The biggest impact in 2012 that was in the early part of the year, and moving forward can’t really say what the weather patterns are going to be but I think the biggest variance of that is behind us was in the first half of the year.

Your next question on the line is from David Paz with Wolfe Research. Your line is live. David Paz – Wolfe Research: Good morning. James P. Torgerson: Hi, David. Richard J. Nicholas: Hi, David. David Paz – Wolfe Research: Sorry, I go back to I just want to clarify in your UI rate base projections that you disclosed I guess those November last year did that – that those numbers are slightly of your rate base you requested in the rate case – the UI rate case? James P. Torgerson: The request in the rate case was slightly higher based on current information. David Paz – Wolfe Research: Great, okay and those projections include any impact on bonus [D&A] this year? James P. Torgerson: No, because in November that time bonus depreciation was set to expire and it was that kind of New Year's Eve surprise when they put 50% back-end. David Paz – Wolfe Research: Okay. Got it so when you say that if we were to take the draft order the rate base that we disclose there that would be ones to add on the renewables, potential renewable project and other things you commented on earlier you would get back to effectively what you disclosed to in those slides at UI last year? James P. Torgerson: Yes, it's pretty much in that ballpark, yes. Richard J. Nicholas: And you may see variances year-to-year? James P. Torgerson: But it’s not that far off. David Paz – Wolfe Research: Okay. Great. And then switching subjects just now that you have I guess one more clarity on the renewables program, you said $40 million, I know earlier you have said that, that is one condition, or one item, one factor, that you’ve been looking at to decide when you would issue equity next, did you have any sense on when that timing of the next equity issuance? James P. Torgerson: We still want to see obviously what comes out of the final decision on August 14 with regard to capital spending, and all the terms and conditions around that, the renewable connections is an agreement and principal, we haven’t yet filed that with PURA. So need to see how that works its way through and the general capital market condition. So we’re still very actively monitoring the variables that would lead us to decision. Richard J. Nicholas: And on that the rate base thing, I just want to add one thing, we that still does include the enhanced tree trimming in that rate base, which is about, it’s about $25 million of capital spending a year, so not $25 million are rate base but it’s and doesn’t start till 2014, so it will have an impact on 2014 and moved into 2014 and 2015 and beyond. But I just want to make sure that’s correct.

(Operator Instructions) So we will go to our next question with Robert Howard with Prospect Partners. Your line is live. Robert Howard – Prospect Partners: Hi. Just one question on just natural gas capacity entering into New England, the transmission capacity. I have been hearing a lot about how last winter you know lots of constraints. Does that create any pressure on you guys for maybe slowing down the gas conversion, I mean are there issues there or is that really a separate topic and there is no sort of pressure to slowdown? James P. Torgerson: There is absolutely no pressure to slowdown. We have plenty of capacity right now and we’ve actually find out from more on a couple of pipeline projects that they’re requesting people to sign up more. So we have plenty of capacity to serve our load and then we were even, we just approved to look at expanding even our LNG facilities. That's in the future set, not going to affect anything in the next couple of years. The problem with the electric generation is, they don’t have firm capacity, whereas we do to serve our distribution customers. We have firm capacity, we have storage and we have our LNG facilities. So we can meet all the needs plus the growth. The electric generators don’t have the firm capacity and that’s why there can be a discontent for them. If you start getting at cold weather, and we could see some issues arise. Now obviously the utilities whether electric or gas, are going to work together, it make sure nothing bad does happen. But you're right, there is some capacity constraints, but both Algonquin and Tennessee are proposing some pipeline expansions that should help. But that's probably not going to happen until 2016. So we’re in good shape. Robert Howard – Prospect Partners: Okay, great. And then just with the CNG rate case, is there anything that could happen in that case that might impact, if you got a certain result there, would that impact your gas conversion program at all or is that really not…? James P. Torgerson: I don’t see that anything that would occur on that case is going to impact us. The only thing that could possibly is that don’t do the decoupling mechanism correctly. But that’s been in a Comprehensive Energy Strategy, I think here in legislation as to how it’s suppose to work, so we should get the growth out of that. I just don’t see anything that’s going to slow us down on our gas conversion activity. There’s nothing in the case that would, I mean really asking for them to fix the use per customer, normalized use per customer, brings us back to where I think we’re currently seeing that will add the revenue. Look at the ROE and then expenses aren’t something that’s going to be a big issue in this case, I don’t think either, because those companies operate fairly leanly its not like we’re asking for big increases in all of them either. That’s really the capital for the pipeline expansion – our replacement program then the expansion related to the adding new customers for the gas conversions.

And next question on the line is from [Leon Dubov for Luminous Cap Management]. All right.

Hey good morning guys. James P. Torgerson: Good morning.

I have two questions, actually one, on the settlement for the slightly higher ROEs or for renewable. Is that – is the consumer advocate in on the settlement as well or I don’t remember if you said or not? James P. Torgerson: Consumer council has been advised of it. They have nothing party to the book; they have been an advisor when we’ve talked to them about it. They are not a party to the agreement at this point.

Okay. And then on the ALJ proposal at FERC, do you have to actually book at lower rates now or only after FERC actually books? James P. Torgerson: We believe all that rate changer but I think it’s after. Richard J. Nicholas: All right, and it would appear that the refund period ends December of 2012 and so, we would continue with the $11.14 until FERC actually orders the 97 plus whatever basis points they determine. Now, having said that there is another complaint that was filed last year that really was filed to extend the 15 month or start a new 15 month refund period and FERC has not ruled on that whether to put that for hearing or about that. So that is still hanging out there.

But for now, we’re booking at the $11.14… James P. Torgerson: Yes.

Okay, thank you very much.

Our next question on the line is from Andrew Weisel with Macquarie Capital. Andrew Weisel – Macquarie Capital Securities: Hi, thanks for taking my follow-up question. In the draft decision when talking about decoupling they said they are going to create a generic docket not only for electric but also for gas and water utilities. How does this impact the need for rate cases at your two gas electricity is given that so much of the focus there is about decoupling the usage core account and is your expectation that the electric and gas may have different decoupling mechanisms whereby electric will be fully decoupled, gas will only be decoupled on a per account basis? James P. Torgerson: I really don't know what's going to happen to this generic decoupling docket. We will see. They haven’t even issued it, I do expect that there would be difference in the decoupling as for electric we have a full revenue decoupling as you mentioned, for gas it would be on a per customer basis, it is what we propose and what is in the energy strategy and the legislation. So I think my guess is that trying to figure out how to implement it and any nuances that would go along with those but they haven't started the docking yet, they haven’t issued anything, so we don't – I don’t know what's going to happen, we have to wait and see them. Andrew Weisel – Macquarie Capital Securities: Okay, fair. James P. Torgerson: (Inaudible) it will be what we suggested… Andrew Weisel – Macquarie Capital Securities: Fair enough. Now if they do come out with something that would be accommodating to the de-coupling per account for gas, would that negate the need for a second gas rate case or would you also want after some of the CapEx factors that you mentioned? James P. Torgerson: Its depends on how I gets implemented, if they say that it automatically applies then that would probably in our minds are need to go for any future rate case for selling (inaudible), they maybe or well say its in the next rate case you filed and you need to implement it, we will have to see what it does, but year if we get implemented immediately and then that would mitigate any need for future rate cases. Andrew Weisel – Macquarie Capital Securities: Great thank you. James P. Torgerson: Perfect.

And next question on the line is for David Paz of Wolfe Research. Your line at live. David Paz – Wolfe Research: Hi, thanks for talking my follow-up question. Did I hear you correctly; will you update guidance soon after you get a final decision in the UI particularly if rates are effective this year? James P. Torgerson: If there was something that was material that would take us out of the ranges that are there. David Paz – Wolfe Research: In then temporarily Jim I think I heard you say what – March or April 2014 final decision in the FERC was that just your guess or is there some kind of schedule out there? James P. Torgerson: Yeah David I’m going back to the what schedule they had originally set out which was anticipating that FERC issue that their six months after all the brief were in from the judges initial decision, so if the briefs are contemplate in the pleadings and reply to the brief in the reply brief, I think goes to October 24th, so we have six months to that, you are probably looking on April of 2015, that’s how I came up with it. David Paz – Wolfe Research: Great thank you James P. Torgerson: Sure

(Operator Instructions) We have no questions at this time. James P. Torgerson: Okay, well thank you operator and thank you everyone for participating in our call. Appreciate your questions and if you have more please don’t hesitate to get a hold of us. And thank you again. Bye.

Thank you. This concludes today’s call. You may now disconnect your line.