Good day and welcome to the PNM Resources first quarter conference call. Today's conference is being recorded. At this time, I would like to turn the conference over to Gina Jacobi. Please go ahead.

Thank you, everyone, for joining us this morning for a discussion of the Company's first quarter 2008 earnings. Please note that the presentation and accompanying materials for this conference call and its supporting documents are available on the PNM Resources website at www.pnmresources.com. Joining me today are PNM Resources' Chairman, President and CEO, Jeff Sterba, and Chuck Eldred, our Chief Financial Officer, as well as several members of our executive management team. Before I turn the call over to Jeff, I need to remind you that some of the information provided this morning should be considered forward-looking statements pursuant to the Private Securities Litigation Reform Act of 1995. We caution you that all of the forward-looking statements are based upon current expectations and estimates and that PNM Resources assumes no obligation to update the information. For a detailed discussion of factors affecting PNM Resources' results, please refer to our current and future annual reports on Form 10-K and the quarterly reports on Form 10-Q, as well as other current and future reports on Form 8-K filed with the SEC. So with that, I will turn the call over to Jeff.

Thanks, Gina. Good morning and thanks for joining us this morning. If I think about the first quarter of 2008, I think what we see is some mixed results. While the financial performance is certainly not acceptable, it is in line with what our expectations and plan were for the first quarter, largely due to the delay incurred last year in the rate relief filing for our New Mexico electric business. But we also did see a number of endeavors undertaken and progress made on some of the fundamental drivers that will affect our underlying business as we go forward. As I said, $0.05 a share in ongoing earnings for Q1 is unacceptable. But it is in line with our '08 plans given the delays in rate relief that we incurred. Recall that the earnings guidance we provided in February, which was both with and without a 100% of the rate relief, so we showed you what it would be if we received all of the rate relief both fuel and non-fuel that we requested, as well as if we received none of that rate relief. Recall that within that guidance, we indicated that PNM Electric would lose $0.16 to $0.31 a share for the year if there was no rate increase. Obviously there was no rate increase in the first quarter, and the first quarter is our lightest load period. We also had multiple coal unit outages that were plants down for scheduled maintenance, so low performance in our New Mexico electric business was expected and unavoidable in the short run. But we also in February gave you a list of key focus areas for the Company for 2008. Chief among those were certainly the electric rate case and improving plant availability. I will talk about both of these…

Thank you, Jeff, and good morning. Let me just start by saying, that the first quarter ongoing earnings as Jeff pointed out that it was within our expectations, and that was driven by the fact that we all knew that the delay in the rate case itself would have a financial impact in the Company without a fuel clause and have a financial impact to the Company. And, as Jeff pointed out, we had scheduled planned outages in the first quarter that were addressing many issues that we are correcting that also impacted the earnings. And I'll talk more specifically about PNM Electric and how that compares quarter-over-quarter. In addition to that, the GAAP earnings represents not only the trading loss at First Choice, but also some write-offs relative to the final rate order, and I'll talk briefly about that. But, again, I want to reiterate two things. One, we won't talk about guidance today simply because the Company doesn't have the final order regarding their fuel clause. And until we have a full decision and know the full impact of that, we'll delay any discussion on guidance. If you go to the next slide and you look at the quarter walk across, you can see obviously what stands out is the quarter over quarter for PNM Electric at $0.35. But before I go into specifics on that, let me just discuss the other aspects of the business. First of all, TNMP earnings was up $0.04 from last year. That was driven by lower operating costs, and also the favorable variance reflects the expiration of the synergy givebacks and some lower interest costs. On PNM Gas we added $0.05 to ongoing earnings. 60% of that really is reflective of the new gas delivery rates and also reflects about a 1.2%…

Thanks, Chuck, and let me close with slide 14, which is a slide that we provided you in February about the checklist of the things we believe we have got to execute on in 2008 and run through these quickly. First, relative to the sale of the New Mexico gas business, we talked about that. It is on schedule. On the acquisition of Cap Rock, we've also talked about that, and it's on schedule and, frankly, on a fairly fast-track. Relative to FCP, we talked about that. Let me raise one other item on FCP. One of the things that we had been struggling a bit with at FCP was the call center that was located in Dallas was having an inordinately high level of turnover, which was making it difficult to provide continued level of customer sat, as well as being able to treat customers with problems and new customers coming on in an appropriate way. And this was a problem recognized at the end of last year, and the FCP folks have successfully transitioned out of the call center in Dallas to a call center in Scotts Bluff, Nebraska where there is except much, much lower turnover, frankly, a higher caliber of individual largely because of that turnover, and a real focus on First Call issue resolution. And we're already starting to see the payoff of having people on the phones that have a better handle on what they are doing, how to treat customers and how to help them understand the value that FCP can bring to them. So that's one item I wanted to just touch on in terms of the call center transition. On ERCOT we talked about Cedar Bayou, and it's moving forward. We're continuing to look at a few other options relative to…

(Operator Instructions). We'll go first to Greg Gordon with Citigroup.

Thank you. At this point, have you closed out the speculative trading positions, and so the remaining non-cash charge taken in the quarter, does that represent the absolute exposure to future cash outflows, or are those positions still open?

Yeah. Greg, this is Chuck. Let me address that. We have closed out the positions, but we're continuing to close out some of the positions that have held for the conversion to the liquid gas position I talked about. And we're in the process of exiting that at this point. I would, frankly, as I mentioned when I talked about this, if we held the position and there was a 20% decrease in gas prices, we'd see some slight reduction of that loss. But at this point, we've made the decision to continue to exit. I would project at this point at most we would transaction costs associated with this thing would incur about another $1.5 million at best. But we're comfortable with the numbers that you see now with maybe $1.5 million to support transaction costs and any slight variance relative to the final completion of that exit.

Thank you.

And we'll take our next question from Edward Heyn with Catapult.

Good morning.

Good morning.

I just wanted to see if you guys could touch on the dividend briefly. I know that you've talked about the emergency fuel clause being the big driver on kind of the overall outlook of the Company. But how much do the unregulated losses that you took this quarter and the weaknesses in those businesses affect the outlook for the dividend as well?

Well, the dividend as we said before is really going to be decided upon looking at many factors, but particularly the long-term prospects for regulatory rate relief and the ability for the regulated businesses to earn an appropriate cost of capital and what that transition timeframe will be. These are what we look at as an exit loss. They don't have in my judgment an impact on our ongoing decision relative to dividends, but obviously FCP earnings are a source of cash to pay dividends. We have not had the utility paying a dividend into the parent. That's something that I believe needs to change so that we can appropriately allow those utilities to operate with the recognition that they have to pay a dividend in order to direct the capital. So I'm not in a position obviously to tell you what's going to happen to the dividend. The fuel clause decision is still a primary element for us in understanding the prospects for a recovery of costs within our New Mexico regulated business. And, as you probably know, we will be having our annual meeting at the end of May and a board meeting at that time. That's the next scheduled time for the board to get together.

And you'd expect to address the dividend at that meeting?

There will certainly be conversation around the dividend. There will be certainly conversation around the dividend with the board. I'm not going to forecast what the action of the board will be.

Okay. Fair enough. And then just quickly on the timing of the debt remarketing and issuance that you spoke about. How does that play into the timing around the fuel clause and decisions like this business about, but do you anticipate having that complete before you get a decision?

The answer is yes. We've launched the deal, as you know, this morning. The portion of that transaction, the 250 at the holding company for the remarketing and the hits is scheduled to be remarketed on the 9th through the 13th. And given the fact that we've launched the transaction today, those other 350 would be at the utility, we would certainly expect that the marketing period over the next couple of days with an anticipation of pricing later this week or early next week. And then that would be certainly an advance of the final decision on the fuel clause having emergency fuel filing that we have a hearing on May 15th. So we will be completed and finished with this financing prior to that.

Great. Thanks a lot.

Thank you.

We'll go next to Paul Fremont with Jefferies.

Yeah. I just want to get a better sort of understanding of the trading activity and the loss there. Was First Choice betting on the differentials and just taking a long position on those differentials, or should we just assume that First Choice had obligations to deliver into congested areas and that your hedges ultimately proved to be ineffective because they were based on past relationships?

Charles Kitowski, who has headed up the trading and sourcing functions both under contract with FCP and also within EnergyCo, is here, and I'm going to have Charles take that question.

Good morning. The position was looking at the differentials between pricing zones within the ERCOT market, and the bet was that those pricing differentials would be reduced. And over time with the extreme transmission congestion that Chuck had mentioned earlier, we've seen that that instability created that differential to increase and hence the overall losses at First Choice Power.

Right. But I mean was that done -- in other words, were you just actively betting on the differentials? Is that the way we should look at it, or should we look at it as the basic underlying business of First Choice requires you to deliver power into congested areas, and you were just unable to execute a hedge that worked?

It was a small speculative position that was put on at First Choice Power, and with the extreme events that we've seen in the market, that position went against First Choice.

Okay.

Let me add something on that, Paul, and this is just as Chuck and I have gone back through from the diligence side as to the position, the logic of the position, et cetera. One of the things that we see within ERCOT is that they made a change trying to rely more on their systems to manage congestion as opposed to the human intervention mechanism that they have used historically. And, quite frankly, that mechanical intervention didn't work effectively at all. And ERCOT as subsequent to a set of these major disturbances that occurred in January and February have put forward a number of changes that call for human intervention more rapidly and also alter the way in which those models are supposed to decongest. And a lot of this has to do with how resources are originally bid in. And, frankly, we're just not comfortable enough with the process they are going about today for congestion management to even consider being in that kind of business at this stage, where it isn't really as much a function of market as it seems to be more a function of the systems that manage congestion and the ability to be congested. And obviously, that is what we have committed ourselves to working with ERCOT on, but we've exited that market.

And the second question really is within the First Choice business, I mean this represents I guess another event that was sort of unanticipated by the Company in this sort of underlying business line. Is there any type of a change that you think needs to be implemented in terms of risk control or how you think about this business to stop, sort of, the unexpected events from impacting quarters like this?

The short answer is absolutely, Paul, and those have been addressed. That's why we have directed FCP, and we and our partner have directed EnergyCo to cease and desist in all proprietary trading, number one. Number two, as Chuck mentioned, the risk management tools that we have in place detected and showed what this issue was. So, they worked effectively in that regard. But I think what happened was we looked at it. We saw that this was largely -- it looked like an anomaly, because we saw the cash market settling positive. So, the forward market demonstrated a loss, but the cash market was settling positive. And the forward market became very illiquid. So a very slight move, a single transaction would move the price on these basis differentials because people fled the market. We looked at that, and if I could say anything, I think probably we waited too long to go forward with the exit. But it was a conscious decision. We wanted to exit. That was the intention. But when we see cash settling positive, it gave us pause as to the way in which we exited. And with hindsight, I would have preferred that we exited immediately and took whatever hit we were going to take. It clearly would have been a hit, but taken whatever hit it would be. There is a set of other things that we've done to put our risk management people in a tighter control of all positions where they have the ability to decide no, we're exiting a certain set of transactions even over the objection of the part of the entity that may have put them in place. But, frankly, the biggest change is, we're just not going to play in that market. Our focus is going to be on ensuring that we procure the resources at the lowest possible cost to help FCP grow its inherent retail position, as well as then on the EnergyCo side, to ensure that we're doing the best asset-backed trading to enhance value possible, but not to speculate relative to the direct market movement.

Yeah. Paul, let me just add one other comment to that. Obviously, this is a hard lesson to deal with, but the other position was the fact that it was an illiquid market. And so, as we look back on that as you mentioned, what things and practices have we learned? Well, first, as Jeff said, we're out of that completely, so we're permanently not going to be looking at those kind of trades period both at First Choice and EnergyCo. But the fact it was an illiquid market as we began to unwind the positions and exit that position that was held, it was not easy to get out of the position without taking on possibly even further losses if we reacted. And finally, when we got 50% out of the position and still saw movement in the market, we got out, otherwise the losses would have been more significant. But at that point, we accepted the fact that the market was not going to reverse itself. And we needed to accelerate our exit strategy and move immediately, which is what we did. And a tough lesson to learn, but again as Jeff pointed out, we're permanently out of that, and also we carry that same decision talking to our partner at Cascade to EnergyCo that we all agree that the market dynamics and the difficulty in positioning yourself in that market with uncertainty is just not worth the risk, and we're out of that for EnergyCo.

One other last data point relative to this congestion issue, as we looked back over '07 in prior years, congestion was typically decongested within a three-hour, at most four-hour window. What we saw in January and February is the congestion, the model that was trying to manage that decongestion was not taking the actions for up to 10, 15 hours. And so consequently, that congestion which drove these basis differentials north of $100 from say $1.00 or $2.00, would last for very extended periods of time. And, frankly, that's not a good thing for the electric system to operate. You need to decongest as rapidly as you can. And I think ERCOT recognizes that, and they are putting in place changes to address that.

Okay. One other question. You talked about $13 million of savings under the energy efficiency program, and there is about $0.02, I think, at PNM Electric in terms of cost savings in your slide. Is that differential I assume consistent with, sort of, the $55 million in O&M increases that you're expecting to see this year, or are you coming in less or more than what you were originally thinking?

We are coming in on plan with the longer-term view looking like we will be able to exceed plan. But that probably won't be seen until we move into 2009. But we are currently well on plan for the execution of O&M savings due to -- you said energy efficiency, I think you meant just process efficiency.

Okay.

We're well on plan so far this year.

But the cost escalation is consistent with the $55 million number that you gave out in February?

We're still seeing increased cost escalation in a number of areas of our business, yes.

Okay. Thank you.

And we'll go next to Maurice May with Power Insights.

Yes. Good morning, folks. I just wanted to pursue a couple of things that have already been asked about. But, first of all on the dividend, the date of your annual meeting and the next board meeting is May 19th, is it not?

No. It is May 28th I believe. It's the Wednesday after Memorial Day. I believe that's May 28th.

Okay. And that is the next time that the Board of Directors considers the dividend?

That's the next time the Board of Directors will be together, yes.

Okay. And then, second of all, I do understand that the prop trading losses do continue into second quarter of '08. But you mentioned $1.5 million. Is that your estimate of the continued losses, or is that just your estimate for transaction costs? I missed that part.

What's the 1.5 million?

Yeah. The $1.5 million would be predominantly transaction costs. And as I mentioned, we put a collar on the gas positions. And so that collar had a cap, and given the fact there have been significant movements in the gas market in Texas, it resulted in a slight, slight adjustment to that loss, but nothing significant from where we were at the end of the quarter. So it's predominantly the transaction costs and a slight movement to reach to the cap that we had put the collar on and then the market conditions we capped off given where gas prices are.

Okay. So the bottomline here would be that prop trading losses in the second quarter would be a little bit more than $1.5 million. Is that how I can read your comments?

Slightly. I mean it's $1.5 million is what we project at this point given the positions that we are in as we…

The loss for the whole quarter?

For the whole quarter. And as we unwind that position, I would only look at about a $1.5 million on top of what you see for the quarter as we exit it completely.

Okay. And my third question has to do with the action on the fuel clause at the commission. Because, as I understand it, at the last open meeting when they did consider the final order for the rate case, the non-fuel rate case, that there was kind of a quick vote that went three to two against authorizing a fuel clause at that point. But, first of all, is that correct? And second of all, can we imply some implication that on May 15th, they will perhaps do the same thing, hopefully with more positive results?

Well, I will allow you to prognosticate about May 15th. Our focus is on doing the best we can in presenting our case on May 15th, and the commission will do whatever it is the commission does. I'm certainly not going to say what I think they will do in this instance.

Well, good luck.

I appreciate that. On the other point, you're right with a slight twist. And this turned out to be a fairly extended discussion. There was a push to put in place a transitional fuel clause, an interim fuel clause immediately that would go into effective effectively May 1, and would be in effect until the time that this final decision on the emergency fuel clause was acted upon. At that point, frankly, that decision could well have moved into the end of May or even going into June, and that failed on a two to three vote. But the outcome was, in fact, the order even has language regarding this -- a strong attempt on their part to come to a decision on May 15 if practicable or as soon thereafter as possible. So that's why I view that as a positive outcome. It shows to me that the commission increasingly understands the importance of the issue. And there were comments made by commissioners about the length of time that this case has taken, that they believe that the cases absolutely need to be able to be done in 10 months. This one has drawn out to more than 15 months. So I think there were a number of positive indications from a timeliness side.

Jeff, who voted in favor of it? Who were the two votes?

David King and Sandy Jones. It became a bit of a discombobulated conversation only because originally a motion was made by David King, which was seconded by Carol Sloan. And then they went off into a number of other points of discussion. As a result, they came back, and instead of acting on that motion, a new motion was made by Sandy Jones, which was then seconded by David. And Carol Sloan who was not present physically, she was on the phone -- and so I honestly can't explain, don't know what may have been going on. She ended up then voting in the negative, even though she had seconded the motion the first time.

Interesting.

And I think when you're trying to do this kind of thing by phone it is difficult. Because this meeting lasted -- and I sat through the whole thing, it lasted probably six hours in total. And that section probably took an hour and a half. But they moved into a number of different topics as they worked to try to resolve the process that they would use for addressing the order. So, I viewed it as a positive sign that they increasingly recognized the importance of timely relief, as well as the issue of the fuel clause.

And your estimate of undercollection on the fuel is $72 million? That was the estimate I think from a couple of months back.

On an annualized…

Yes.

Yes.

Still the same?

At this stage, yes.

Yes. Okay. Thanks, Jeff.

And we'll go next to Lasan Johong with RBC Capital Markets.

Good morning. I think I'm going to have to take a slightly different tact on this trading issue. I just need to get a couple of things straight in my mind here. Chuck, you mentioned that the occurrence that led to this loss was nonstandard deviation move in the basis differential. Correct?

That's correct.

And typically this trade would have earned you about $1 million to maybe $1.5 million in a typical quarter?

$2 million to $3 million for the year is what we would have…

$2 million or $3 million for the year. So essentially a nonstandard deviation move, which I believe is well into the trillions to one type of percentage…

Yes.

…I'm not sure the math works out in your favor to close this operation down. Because if that's really the case, at worst should you not wait until all this discombobulation is removed from the market and say, you know what, we can now go back to a relatively predictable model and make that $2 million or $3 million earnings per year because this is unlikely to happen for another -- god, I don't know at least 100 years?

This is Jeff. Let me take that one because you've tapped into obviously a lot of the discussion that we had. Frankly, the driving point for me, Lasan was, we're operating in a market where how that market is operated, particularly on the decongesting inside, by the market manager has a dramatic impact. And I'm not willing to bet on how that will be done in the future. We believe that we know what the intention is, but it's not their capital, it is our capital, that's placed at risk. We don't manage that. And so, consequently I just do not believe it is a business that we should be in. Once they moved to nodal market, they have got some enormous challenges from a market management side to go through. A lot of their attention is focused on trying to drive to the nodal market implementation. And we're just not in a position -- we don't have the size, scale or appetite for taking on that kind of management, market management level risk at this stage. And so we believe that the prudent thing to do was to exit it. When we saw cash settlements being positive, it gave us pause because it said that the fundamentals can return. But frankly, the forwards continue to drift down or drift up, and the result was just not tenable for us.

On that basis I would agree, but then like I said, is it not the case that you should then say to yourselves, well, let's wait this out because ERCOT has no incentive to see basis blowouts to 100,000 megawatt hours period. And so, they will most likely have a fixed on this by the time they get to the nodal market situation. Would that not be a correct assumption to make?

In my judgment, no.

Okay.

And the reason, Lasan, is I just -- their focus its on moving to the nodal market. They are trying to make changes to the system in which they manage congestion, but I think they are dealing with something that's larger than they anticipated. Look at what happened when we almost had a near term transmission crash because of the dramatic change that happened in wind. I mean there are some elements of this that I think are an ongoing struggle from a market and system reliability management side. And I believe they are in good faith addressing it, but I'm not going leave our capital at risk on the basis of their getting it done.

Yeah. Lasan, let me just emphasize that too is that we didn't find any reason to think that the transition congestion that was reflected in those losses on the forward curve were reality. And so we held and monitored the position in anticipation of it reversing, but we also had a lot of communication with ERCOT operations in trying to understand if there were problems. And frankly, based on our own analysis and communications, et cetera, we did not see any clear path that indicated that there were problems in the market. However, since then, as you've seen from this slide, there are problems, particularly in the West zone with wind generation and how to monitor that relative to the control system. But I mentioned also we're taking very proactive steps that we're engaged with ERCOT operations along with a lot of other participants to better understand exactly how ERCOT is going to be managing their control system going forward, particularly with the impacts of the wind forms that continuously get an operation in that West zone. So we're just not comfortable that the information that we were able to obtain and looking forward that it's adequate enough to want to take any risk in a volatile market with those uncertainties in that market. And so I agree with Jeff, we've made the right decision to move out and not put our capital at risk.

Understood. Now, that's obviously not the case on your prop procurement at FCP and then TNMP. I'm assuming you're not still continuing to do what you do there to procure power and optimize the procurement around the trading of the power?

Absolutely. Both from a hedging on price side -- we're about 85% hedged on FCP moving into 95% hedged. So we're both from a hedging, as well as an optimizations side. Wholesale optimization is a major part of our strategy, and we will continue forward with that.

Okay. That's good. Directionally on the -- I know you're not going tell us how much you expect to apply for in the rate increase, but directionally what are the components? Higher interest expense, higher prop purchase prices, less the $34 million granted by the PUC, lower op expense by $1 million to $2 million and higher availability on plans?

The other major item that you missed, Lasan, is significant capital additions. We've got $150 million or so that's being spent on the San Juan plant environmental retrofits. We've got about $100 million, $120 million in fundamental T&D being spent each year. Plus, we have a purchase power contract for a peaker that goes into effect this summer. So there are a number of things that will cause upward pressure. Now, we're certainly not at a point of being able to say what we think it is. The test year will probably be based on a March ending test year, and obviously we have just disclosed that. We have not turned to the rate analysis yet. But capital costs or cost of capital obviously is, if we look at what we're having to do on the debt side, it has moved up.

Okay. The last question, Chuck, how are you going to get the bond market comfortable with the fact that you don't have the fuel clause in hand today? What is it that you can tell them to say, don't worry about it?

Well, certainly we have had those discussions with the lead underwriters, Lehman and Merrill and Banc of America. And we've set this transaction to go to market with that uncertainty that still remains. But we know exactly where the rating agencies are today. Frankly, I think the bond market will take in consideration the current credit profile of the Company and understanding that that credit profile already factors in some risk associated with the regulatory side of the business. The markets are open right now and look to be a good time to approach that. And we think it is best to go ahead and pursue it. And even with some slight uncertainty around the regulatory piece of the business. But with that happening in there and knowing that we're going to address something on May 15, there is an additional risk if we were to wait and determine whether or not we could go to the market at a later time and take additional price risk and access to that market. So, we really feel comfortable based on the discussions with the underwriters that we can pursue this at this time and price the deal as best we can in the next few days.

Are you going to push for any resets of the interest rates on upgrades of your credit profile?

No, we really don't have a rate reset feature within the security. I think at this point, we're going to price it based on where the market is today relative to our credit profile with the split rating that we have at the utility and with the BB rating at the holding company. The covenants in the deal itself are reasonable, and we're comfortable that we can go ahead and execute and get some momentum in the market as it is today.

Are you optimistic at all that S&P will reverse course if you do get the fuel clause?

You know, frankly, in my view towards discussions with S&P, no, there would be no immediate reverse. They put us on stable outlook. I wouldn't expect at this point there would be any immediate action. They generally want to see a trend and some solid decision making out of the regulatory process with the commission. So I think certainly they have commented on the need for support in our fuel clause, and that directionally is important, and they will be looking very hard to see what kind of decision comes out of the commission. But they also want to see that the business going forward that the commission will continue to find ways to support the utility to get its financial health back. So, one event certainly is not enough. We've said that it will take multiple rate increases and we'll file for another rate increase in regard to where we stand today. But it will take some directional and some support out of the regulatory side of the business to get ourselves into the final financial position and stabilization that we are seeking.

Operator, this is Jeff Sterba. I think we've got time for one more question.

Thank you. We'll take out last question from Paul Patterson with Glenrock Associates.

Good morning, guys.

Good morning.

Just a sort of follow-up on, I think it was Paul Fremont's question, with respect to this anomaly I guess that seems to be happening in the congestion in the ERCOT market, is there any potential at all in terms of this issue going into sort of a non-trading issue in terms of First Choice buying and sourcing its power, or is there anything we should be thinking about on that whatsoever? Could you just give us a little bit more clarity and comfort with respect to that?

This is Charles Kitowski. Good morning. First Choice, through its current strategy over the last several years, has been purchasing power in multiple zones to serve our customers. And there has been some adjustment around the supply portfolio, but nothing significant as we move forward for the rest of the year.

Okay. So basically this issue, regardless of what happens with it, really shouldn't impact any of the other businesses now that you are exiting the business? Is that a good way to look at it?

That's a good way to look at it.

Okay. And just finally, on the filing you said that you might do another filing in the third quarter for a rate increase. Why wait until the third quarter? Why not do it sooner I guess considering how slow this commission has been in responding to your rate requests?

Well, remember that the third quarter starts in less than two months. And we have got the best we can use is a test year of ending March 30th. And the process of pulling together what are called the minimum data requirements of a rate case in New Mexico is not a simple process. So it does take some time to pull together. We want to make sure we take into account the results of these decisions, as well as other learnings about how to best go forward with the rate case. I think in one sense not only we but the commission and the staff and interveners are rusty about rate case litigation because, frankly, we have not had any on the electric side for many years, and what we have had are settled rate reductions. So with the settlement being done before the filing is made. So we want to make sure that we take those things into account, and frankly, I think third quarter would be pretty speedy. But remember third quarter -- a quarter lasts three months, and the start of that third quarter is less than two months away.

Okay. Thanks a lot guys.

You bet. Thank you, Paul. Operator, I think that was the last question that we have. Let me thank you all for joining us. I know that the trading loss issue is one that I hope we've explained to your understanding and satisfaction. Clearly, we don't like the result of it, but there are many extenuating circumstances associated with its cause. As Chuck said and I said early on, that in terms of the baseline operation and ongoing earnings, we are effectively at what we expected in the first quarter. Obviously, that's not where we expect to be first quarter next year for both this rate case and for other reasons, and we'll continue to focus on the items in that last slide about areas of focus that you can chart our progress on as we go forward this year. Thanks very much.