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Executives

James S. Pignatelli - Chairman, President and Chief Executive Officer

Kevin P. Larson - Senior Vice President, Chief Financial Officer and Treasurer

Jo Smith – Director of Investor Relations

Analysts

Rajeev Lalwani - JP Morgan

Brian J. Russo - Ladenburg Thalmann  

Judd Arnold – King Street

Robert Howard - Prospector Partners

Peter Hark – Talon Capital

William Young – Longbow Capital

UniSource Energy Corporation (UNS) Q1 2008 Earnings Call May 9, 2008 12:00 PM ET

Operator

Good afternoon. My name is Sylvia and I will be your conference operator today. At this time, I would like to welcome everyone to the UniSource Energy First Quarter 2008 Conference Call. Today’s call will be hosted by James S. Pignatelli, UniSource Energy’s Chairman, President and Chief Executive Officer. [Operator Instructions]

Before we begin, I’d like to turn the call over to Ms. Jo Smith, Director of Investor Relations. Ms. Smith, you may begin your conference.

Jo Smith

Thank you and thank you everyone for joining us today. In a moment, Jim will brief you on UniSource Energy’s first quarter financial and operating results for 2008. However, I first need to inform you that forward-looking information contained in this call with respect to the revenues, earnings, performance, plan, strategies, prospects and other aspects of the business of UniSource Energy may involve risks and uncertainties. Actual events and results may, for a variety of reasons, prove to be materially different from those indicated in the forward-looking statements, estimates and projections.

Factors that could influence actual future outcomes include, but are not limited to, the outcome of regulatory proceedings, the cost of fuel and purchase power, performance of TEP’s generating plants, weather, resolution of tending litigation matters, the cost of debt and equity capital, changes in asset depreciable, changes in accounting standards, the pace and strength of the regional economy, and other factors listed in UniSource Energy’s Form 10-K and 10-Q filings.

In addition, the forward-looking statements in this call may include assumptions, expectations, predictions, intentions or beliefs about future events. UniSource Energy cautions that actual future results may vary materially from those expected or implied in any forward-looking statements. More information about the risks and uncertainties related to these forward-looking statements are found in UniSource Energy’s SEC filings which are available on the SEC’s website.

Now, I’ll turn the call over to Jim.

James S. Pignatelli

Thank you, Jo. Thank you all for joining us today. Today, we’re reporting a loss in the first quarter of about $0.07 per diluted share. This is compared to a gain in the first quarter of last year of $0.14 per diluted share. The main cause of the differential is frankly higher gas prices, higher purchase power costs that we’re incurring currently. When I look at the revenue aspect, we’re up slightly under 1%. We had a moderate first quarter. Our heating degree days were actually down 6% as compared to last year.

The main element though that has caused this differential is a higher gas prices. Gas prices are up over 16% first quarter of this year versus first quarter of last year. And the cost of purchase power is up 34% first quarter of this year over first quarter of last year.

Performance during the first quarter was slightly below what we anticipated mainly caused by unexplained outages or unanticipated outages at San Juan. We also brought forward a one-week outage from Springerville to Q1 from Q2, which negatively affected us in the first quarter.

We are also incurring as we had informed you before higher coal costs, pretty much in line with the $18 million annual amount, which we discussed in the first quarter of coal cost increases over last year. Additionally, first quarter was impacted by mark-to-market losses which will reverse during the year and we did not make any sales of vessel-to-allowances. We held them and will be making the sales in the future of this year. So that also caused a differential.

If I look at the new customer growth, it is slowing at this time. Historically, from 2002 to 2007, we saw about 2% customer growth and another 2.5% increase in demand from usage per customer. That resulted in a peak over peak of about 4.7% increase for the period 2002 to 2007. We’re still seeing the usage per customer going up but we are seeing a decline in the rapid growth of new hookups.

When I look at the remainder of this year, we are still forecasting a forward curve for gas and power prices will likely impact the comparative margins between last year and this year in Q2 and Q3.

Looking at the UES, UES net income was up. That really resulted because of a very cold winter on the gas system and it reflects some higher prices which we were able to get the rate increases for. We do have a filing for a UNS Electric, which should be acted on in open meeting on May 14th, which should give us an increase at UNS Electric and we will put out an 8-K as soon as that decision is rendered. We have filed another rate case of UNS Gas because the prior rate increase we did not feel was adequate and we’re under discussions with the staff in determining when the filing will become effective.

Going back to our outlook for the remainder of 2008, as I indicated the forward curve on gas and power prices will dampen if these curves come in as expected. If the prices come in as expected, it will dampen our gross margin in Q2 and Q3. We have seen since the last call a 31% increase on a balance of year power prices when I look at a flat price around the [inaudible]. And we have seen about a 33% increase in the cost of gas as we look at it. We still have about 500 gigawatt hours remaining to sell. Over half of that is in the fourth quarter.

Our current gasage position, we have hedged about half of our gas for this year at $8.34. Current market is about $10.15. We will be putting our hedges as required going forward. The 500 gigawatt hours remaining to be sold in the power market is not quite provide they absolutely hedge against the additional gas which we will have to buy in the second and third quarter. All of this really reflects our needs and demonstrates the need for a fuel purchase power agreement. There is a great deal of volatility as you all know in these markets. We’ve been operating in this company for a mild time of twelve years without a fuel purchase power clause. That is one major aspect in our settlement.

As I indicated in the call in February, we did have some problems at Springerville relative to the clean up systems. We had some modules that had some issues. We have completed the repairs on Springerville 1 modules and we should complete the repairs on Springerville 2 modules by the middle of next month. We are operating at just a marginal 10 megawatt D rate currently at Springerville 2.

We continue, or we just commenced, I should put it that way, deferring the revenue from the extension of the CTC so there will not be any revenue recognized on a current basis from the collection, or the extension of the CTC, until the resolution of the settlement.

Adjusting for all the timing differences between the first quarter and what we had forecasted, we are slightly below our expectations for the first quarter. But looking out, we believe there are just so many uncertainties related to the proposed settlement agreement in the TEP rate case that it would be better for us at this time to withdraw outlook for 2008. I know most of you are focusing on 2009 and as soon as we have a final settlement, we will put an 8-K out with all of the details of this settlement. But 2008 is going to be impacted by the resolution of this settlement agreement. We don’t have agreement yet on the true up revenues and that’s not going to be covered in the settlement agreement. That will be up to the Commission.

Additionally, we don’t know when the effective date of any clause for rate increase will be. In my opinion, once a settlement has been heard and acted on, there’s no requirement to wait until 01/01/09 for a rate increase. While it’s agreed that we are revenue deficient and there certainly should be no requirement for us to wait until 01/01/09 to increase our rates. But that again is subject to a timing of any rate action by the Commission.

Additionally, we believe we will go back on FAS 71. That’s under consideration by our outside accountants. There may be one-time impact on 2008. Earnings, for example, we expensed some coal renegotiation clause in prior periods. In fact, if we achieve recovery of some of that as is contemplated in the settlement that could cause us to put an offset on the books and create revenue during 2008. But at this point in time, there are just so many uncertainties with that that we think 2008 gives you a meaningless comparison to what the future holds. So we are withdrawing our outlook on that. Our saying that our cash flow from operations for the full year 2008 is still expected to be in excess of $285 million.

Let’s look at the specifics of the proposed settlement agreement. All of these have been disclosed in the 8-K but I would like to just recall and bring them to your attention. The settlement would us back on cost of service rate making for TEP’s generation assets on a going-forward basis. Our base rate increase would be 6% over our current average retail rate of $0.084 rate. The fuel rate which the PPFAC would balance around would be $0.029 for kilowatt hour. That is the amount of the fuel that’s included in the new base rate, $0.029. Fuel incurred above or below the $0.029 would either be debited or credited to a fuel and purchase power clause.

We would hold base rates frozen through January 1, 2013. The proposed settlement agreement, as I indicated, does not address the treatment of any true up revenues which result from the extension of the CTC rate and we are currently starting to collect some of that true up revenues. But it does state that if there is true up revenue, the first $32.5 million of any true up revenue would go as a credit to the PPFAC account. So it would be credited to future fuel rates.

Additionally, as I’ve indicated, the proposed settlement does not address the effective date of any possible rate increases. We have also included in the settlement a increasing block rate structure for residential. We have incorporated what I would call a life-mind concept and then two rate blocks above it which have higher rates, as you’ve consumed more electricity. The increase on the average residential bill would be less than 6%. We have also agreed to hold at current rates, people on low income allowance. We would not raise them at all. That covers about 17,000 customers, my recollection.

Important to us and essential to us is that this agreement includes a fuel and purchase power clause so that the volatility in earnings, which you have seen in the past, which results from changing and rapidly changing, and consistently changing energy prices, fuel prices, purchase power prices would no longer impact earnings on a per-year basis.

I believe that the settlement is fair and balanced. I hate to sound like FOX but basically, it is a fair and balanced settlement. Customers, you may recall, residential customers, any of our customers, have not had a price increase in a number of years. And in fact, the prices are 1% below what they were in 1994. I defy any of you who defined another utility that can make that statement.

We are agreeing to less than a 6% rate increase since 1994 for our average residential customer. However, the rate settlement will provide us with additional cash flow. It provides us with those cash flow necessarily to internally fund transmission and distribution and some of the generations that we will need. Puts us in a better position as far as cash flow. For the shareholders, it will improve our earnings per share going forward. It will provide stability and earnings per share going forward and it removes the necessity to put the issues before the judicial process which would take years to settle.

Yesterday, the Administrative Law judge established a deadline for filing the settlement agreement of May 29th and we expect to meet that deadline. There’s no disagreement right now between the parties that are going to sign the settlement agreement as to the intention of the settlement agreement. What we’re doing right now is we’re smithing the agreement as necessary whenever you put a lot of attorneys together. We expect Judge Rata to issue a proposed schedule for hearings sometime next week and we would anticipate the debt schedule will provide for hearings, commencing and concluding in the first half of July.

Settlement process has been going smoothly. We haven’t had any hiccups. During yesterday’s conference, a following party said that they would likely support the settlement agreement: The Arizona for Electric Choice in Competition, the Arizona Investment Council, which is formerly the AUIA; the [SWEET], which is a southwest energy deficiency program. Project said that they had one issue. It’s not with so much the terms of the settlement agreement other than how they relate to the timing of the implementation of demand site management programs. And that is in the staff’s hands. Department of Army indicated that they would likely sign on and all other groups, with the exception of RUCO, who indicated that at this time, it was likely that they would not be a part of this settlement. So I believe by the end of this, you’ll have all parties with the exception of RUCO and with the exception of [SWEET] on one specific item that is not in our control to sign on. As I said, we expect hearings in July. My counsel says in July and August, hoping that we can get all this concluded in the first two weeks of July.

With that, I’ll answer any questions you might have.

Question and Answer Session

Operator

[Operator Instructions]

Your first question comes from the line of Rajeev Lalwani from JP Morgan.

Rajeev Lalwani - JP Morgan

Hi, just two quick questions. One: Can you talk about what’s going out with the generation asset and whether or not there’s going to be change in the accounting, if you’re going to be shortening lives and writing up assets again? And then two: Can you tell us what you’re expecting your average fuel rate to be in 2008 that’s comparable to the $0.029?

James S. Pignatelli

In answer to the second question, I don’t have that number, Rajeev. In answer to the first question, could you repeat it? It had to do with the accounting on the generation?

Rajeev Lalwani - JP Morgan

Yes, because I remember years ago, I think you extended the lives of the generation assets, that you brought down the, I guess, in depreciation. And then now that’s in contemplated and like reversing it.

James S. Pignatelli

Correct. The depreciation lives, they’re going to be established in the actual settlement, or approved in the settlement, are approximately the lives we have now. However, the depreciation lives on a go-forward basis will reflect cost of removal in them and there will be some depreciation in the expense in the current settlement coming up to that 6% which reflect some of that cost of removal, bringing reserves up to a current basis.

I don’t have the actual depreciation lives and adjustments which will be made on the going-forward basis but as soon as the settlement agreement is made, that’s one element that will come out in the 8-K.

Rajeev Lalwani - JP Morgan

Okay. Do you have a general order of magnitude if it’s a couple million dollars?

James S. Pignatelli

I don’t have it at this time.

Rajeev Lalwani - JP Morgan

Okay, thank you.

Operator

Your next question comes from the line of Brian J. Russo from Ladenburg Thalmann.

Brian J. Russo - Ladenburg Thalmann

Hi, guys.

James S. Pignatelli

Hi, Brian. How’re you doing?

Brian J. Russo - Ladenburg Thalmann

Good. How are you?

James S. Pignatelli

Fine. Thank you.

Brian J. Russo - Ladenburg Thalmann

Just real quickly, the $18 million of higher coal cost that you expected in 2008, how much of that was incurred in the first quarter?

James S. Pignatelli

My recollection was about $5-6 million of it. Our coal costs were about $5-6 million. Our quarter to quarter comparison, but it had to do with the mix of the coal plants we were running. Springerville, as I indicated, we had an outage there and that is one of the more efficient coal plants. We ran [sun 4] at almost 98% during the first quarter of availability factor and that is one of the more expensive coal plants. And then also, some of the San Juan expenses. So, we still believe that the $18 million in year over year coal costs, if we operate at 87% availability factor for the coal fleet, that it’s still in the $18 million range and $5-6 of it was incurred in the first quarter.

Brian J. Russo - Ladenburg Thalmann

Okay, great, and then also I believe you originally expected about $15 million of higher purchase power expense. It looks like you’ve exceeded that in the first quarter at $21 million. Just wondering, is $21 million kind of a new run rate for 2008, or is it likely to exceed that because you’ve got another Springerville unit coming down for maintenance?

James S. Pignatelli

I’d have to look at it this way. The equivalent availability factor of the coal plants in the first quarter was 83%. The forecast which we previously provided you was an equivalent availability factor of about 87%. So, the purchase power on a relative basis the way you just stated it was higher in the first quarter than it will be as we go out. As we run the plant, our own fleet at higher availability factors. So I wouldn’t say that we have upped our anticipation of purchase power. Did that help?

Brian J. Russo - Ladenburg Thalmann

Yes, that helps. Also, can you just talk a little bit more about the tentative settlement, and specifically, just the base rate freeze from, I think, 2009 through 2013. What are your thoughts on any capital expenditures needed to upgrade the system or build new power plants? And how will you see recovery of those costs?

James S. Pignatelli

Yes, we’ve gone out and looked very carefully of a going-forward basis, naturally, going back on ‘71 from generation creates a UDC rate as you go out. But the majority of our cap ex is on transmission. It’s a higher amount on transmission than on distribution. Transmission is really covered by FERC rates, but we look very carefully at our cap ex going out there, Brian, and we did not see any dilution in earnings capacity with the plant we’re bringing on versus depreciation that was being incurred to that 2013 timeframe.

Brian J. Russo - Ladenburg Thalmann

Okay, great. That’s helpful. And then just lastly, you mentioned earlier about power prices at the power availability, how relative to cash prices. I guess what you’re saying is that are spark spreads contracting and I think initially maybe sometime you expect that to correct itself in the fourth quarter. Maybe you could add some color on that.

James S. Pignatelli

We have thought for a while that power prices should pick up a little bit. They haven’t picked up as much as we had anticipated but really what we’re seeing is that we don’t have that amount of excess capacity to sell because of growth to offset that gas that we have to burn now in the second or third quarters and that’s the additional why this fuel cost is so important. We’re just growing through that excess power as I’ve indicated in the past. We don’t provide with the differential amount between summer gas and shoulder power sales in with the amount of excess power coming down that we have to sell. We just don’t see that natural hedge which we have had in the past.

Brian J. Russo - Ladenburg Thalmann

And so, year over year, are spark spreads down at power availability?

James S. Pignatelli

I don’t know. I’ll have to check that. We’ll get back to you on that.

Brian J. Russo - Ladenburg Thalmann

Sure, okay. Thanks a lot guys.

Operator

[Operator Instructions]

Your next question comes from the line of Judd Arnold from King Street.

Judd Arnold – King Street

Hi. Question with the settlement. I’m just going back to the last time you guys were out in New York. We went through sort of what the key points were in the differences between the staff’s position and your position, sort of where the settlement came. Just interested in getting your thoughts. I understand that you guys have to be with the political dynamics, obviously, far more than we do but you gave away the $800 million legacy rate freeze from ten years ago how much you would have earned. Looks like Luna rate base. It just seems like a ton was given away and after 13 years finally going to be a 6% rate increase. And I guess the question is we clearly gave away a lot so how much certainty do you have that whenever we going to have to file again?

James S. Pignatelli

Well, that’s a broad question. I never have a problem again.

Judd Arnold – King Street

It just seems like we’re giving away a ton of deals obviously far better than litigating but the upside of litigation is your own testimony showed from the Supreme Court, the former Supreme Court justice was the case to win just on $800 million number was pretty darn good. And to give that away, plus outside of rate based shareholders, just a lot was given away. Certainly, there’s obviously a price for certainty but at the end of the day a 6% rate increase, it seems like clearly the company went up above and beyond the call of duty here. I was just wondering what your comfort level was go-forward on a regulatory relationship and at least that there’s been an acknowledgment that we gave away far more than needed to be given.

James S. Pignatelli

I think we did come a long ways to meet this level. I believe that we come out a much stronger company with less uncertainty. I believe if you look at the cash flows that are produced from this that we are in a very good position to support all of our requirements for growth. I believed that the fuel clause provides a great degree of protection going forward in a very volatile market. I believe we had good and valid arguments for our position but anytime we go to court there is a risk that you’re not going to be successful. And I believe in the end that unless you have a constructive ongoing relationship with the Commission, the shareholder suffers. I think if you go back, I think it’s a fact that in those jurisdictions where there is a firm understanding of the operations and utilities by the Commission and a constructive relationship, two things happen: Rates are lower and return is better. The shareholders are more fairly treated and it results in a fair treatment for the customer.

I think that this settlement could I have argued for a 15% rate increase, we could have argued for 15% rate increase. Will we have gotten a 15% rate increase? I don’t think we would have gotten a 15% rate increase. Are our rates going to be lower than APS? Yes. Are they what they need in our belief to provide a fair return to our shareholders? My answer to that is yes too. It’s a balancing thing and I tell you, I believe that this is just a good resolve for all parties.

Judd Arnold – King Street

All right, I appreciate your thoughts a bunch. I appreciate it. Thank you very much.

Operator

Your next question comes from the line of Robert Howard from Prospector Partners.

Robert Howard - Prospector Partners

Hi there. I guess first off, I want to echo Judd’s statement there. It does seem like you guys gave up a lot but I think that you made some good points there and you’re looking forward to being able to analyze the final document there and believe that you said your sacrifices was worthwhile and see if that actually works. But then also, just wanted to ask about when you guys were talking about the rate freeze through 2013, what kind of impact would that have on, say another opportunity for Luna came up and you were able to get an asset at a nice discount. Is there any flexibility or would this type of agreement discourage you to take that opportunity because it would be so long before you could get it through your rate?

James S. Pignatelli

My approach would probably be to buy it that inner source and not buy it at TEP. If I can get an asset at what I believe is below market and I don’t believe I’m going to get an equitable treatment ultimately in a rate-making sense, then I’ll buy it for the shareholder’s benefit and sell the power into the marketplace.

Robert Howard - Prospector Partners

So you think you’ve got enough flexibility there at the current level?

James S. Pignatelli

Yes.

Robert Howard - Prospector Partners

Great. Keep working on this settlement and we’re looking forward to the end of this long march.

James S. Pignatelli

Okay, thanks.

Operator

[Operator Instructions]

Your next question comes from the line of Peter Hark from Talon Capital.

Peter Hark – Talon Capital

Hi, Jim. It’s Peter Hark from Talon Capital. How are you?

James S. Pignatelli

I’m fine, Peter. How about yourself?

Peter Hark – Talon Capital

Very good. Thank you.

I just have a few questions with regards to the way the fuel cost will work as contemplated currently. There was a previous question that referenced the $0.029 and relative to where you are in ’08. I was just wondering if you could kind of talk conceptually about what amount of fuel is contained in the rates under the ’99 settlement, if there is anything explicit. It was my understanding that it really wasn’t, that it’s just incorporated in that average $0.084. So it’s difficult to make a determination as to what the “step up” would be in the fuel rates.

James S. Pignatelli

Right. We don’t have anything specific in the $0.084 as far as what a fuel rate would be. The best I can do to help you on that is the fuel and purchase power cost in 2007, as we just reported, was slightly over $0.03, like $0.0302 a kilowatt hour. So the actual cost incurred in 2007 would have produced an under collection when compared to the $0.029.

Peter Hark – Talon Capital

Got you, Jim. Thank you. And then, as the settlement relates to the wholesale revenue turn back from short-term sales and trading, first, just wanted to be clear on what effectively that amount was in ’07 but under the fuel clause, would the cost of generating wholesale be picked up under the fuel clause as well?

James S. Pignatelli

The cost of generating short-term wholesale is picked up in the fuel clause. The cost for the long-term wholesale is jurisdictionalized out just like the rate base is jurisdictionalized out.

Peter Hark – Talon Capital

Okay. And then what was the discreet amount again of the short-term sales and trading from ’07?

James S. Pignatelli

The pre-tax in 2006 is lacked I have out of our test year was $25 million pre-tax.

Peter Hark – Talon Capital

And that was just the short-term and trading piece, not the total wholesale?

James S. Pignatelli

Yes, because it shifts in short-term that goes through the fuel clause. The long-term wholesale, any profit on that is not included in the PPFAC.

Peter Hark – Talon Capital

Oh, perfect. Thank you. And then, just again on the fuel clause. How would the balancing account work to the extent that you do exceed the $0.029?

James S. Pignatelli

I’m going to give you the way I think it sets the difference between the $0.029 and any of actual fuel costs if it was $0.03, then you would put that difference as a charge into the fuel clause. And then in April of each year, the amount of under or over collection would be taken into consideration as well as the estimated forward cost of power for the year and that would determine whether there was a fuel rate surcharge that amortized any under or over collection and adjust the rate to the new forward-looking curves.

Peter Hark – Talon Capital

Got you. Thank you. And so that would just be done annually? Is there any thoughts or has there been any discussion to do that more frequently, say for instance, if you went to $0.04 you maybe didn’t anticipate that, it would put you in a cash flow circumstance that might need to be addressed more quickly? Maybe get a quarterly or is that something you think about?

James S. Pignatelli

We think about it but the settlement contemplates an annual but once again, it contemplates setting it with the forward-look. So hopefully, that $0.04 unless it was a through a market apparition, you would have anticipated that when you said it on the forward.

Peter Hark – Talon Capital

Okay. Fair enough. And then just broadly, in listening to the proceedings yesterday, there was little concern that the settlement wasn’t already offered up, the details of that. It sounds like you’re working on it and kind of dotting the i's and crossing the t’s but is there a chance at least that you might beat the May 29th deadline or should we look forward to on or about that date?

James S. Pignatelli

If it’s under my control, you’ll get it tomorrow but it’s not under my control. It’s under five parties wanting to dot the t’s not the i's, and cross the i's and dot the t’s. So, the 29th.

Peter Hark – Talon Capital

Okay. Jim, thanks very much. Good luck.

Operator

And you next question comes from the line of William Young from Longbow Capital.

William Young – Longbow Capital

Hello. I was wondering if you could tell us if there’s a specified ROE or if I should expect to see a specified ROE associated with this settlement at all?

James S. Pignatelli

Kevin will answer that.

Kevin P. Larson

At this point, it’ll be part of the settlement agreement and that will be disclosed once that settlement agreement is filed. But you’ll see the company requested 10.75% and the staff and the other parties were below the 10.75%, so again, the number will come out as far as the settlement discussion, or settlement agreement.

William Young – Longbow Capital

And should we expect that the fact that you’ve agreed to have a rate freeze until 2013? Should that have affected the ROE that was, that’s important that’s part of the settlement?

James S. Pignatelli

The settlement’s made up of many aspects and so is rate of return. We took into consideration any possible dilution caused by delay in what we were willing to accept. So, what the numbers you see reflect all of our concerns about dilution. They cover our concerns about dilution.

William Young – Longbow Capital

Okay. So you had mentioned earlier that most of your capital expenditures, are going to be on the transmission side but there are going to be a substantial melt on the jurisdictional distribution side also, and on the generation side. So with the capital expenditures that you’re spending as well as cost increases on the offering cost side, how should we expect the return profile to look during the next four to five years?

James S. Pignatelli

I guess I can only answer that I am satisfied with the return profile going out. I’ve looked at our cap ex. I’ve looked at all aspects of our costs and I feel good about the results.

William Young – Longbow Capital

Okay, thank you.

James S. Pignatelli

Okay. Well, thank you all for your attention and for your probing questions on 8-K. Hopefully, the first week in June that assumes the settlement completed, signed May 29th. Hopefully, hearings first part of July and I’m going to push as hard as I can to get a new rate increase in effect this year. Thank you so much.

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