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Executives

Gina Jacobi - Corporate Communications

Jeff Sterba - Chairman, President and CEO

Chuck Eldred - CFO and EVP

Charles Kitowski - President, Marketing and Trading

Analysts

Greg Gordon - Citigroup

Edward Heyn - Catapult

Paul Fremont - Jefferies

Maurice May - Power Insights

Lasan Johong - RBC Capital Markets

Paul Patterson - Glenrock Associates

PNM Resources Inc. (PNM) Q1 2008 Earnings Call May 7, 2008 9:00 AM ET

Operator

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.

Gina Jacobi

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.

Jeff Sterba

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 in a bit more detail in a moment, but we're seeing real progress with our plants as they exit from major overhauls that are necessary for 30-year old units.

Another piece of news that is positive for us as you likely read about the securing of bridge facilities at PNM the utility for $400 million. We've also secured for TNMP, a $120 million of our revolver facilities. I know that slide 3 shows $80 million, but we have another $40 million commitment as of last night. So it's up to $120 million for a total of $520 million in our two utilities.

So I believe we've addressed the near term liquidity challenge that we faced within our regulated operations that have significant capital expenditure challenges, and Chuck will address this a bit more in detail and speak to our plans in the long-term debt market.

Additionally in last night's news release, we also reiterate that PNM has entered into three-year agreements to sell power from Palo Verde-3. We've seen received $70 million in prepayments, which represents a portion of the value of these deals and further demonstrates the strong asset value this unregulated asset will have in the future. And I'll talk a bit more about that in a moment.

Regarding our financial results, I indicated our ongoing earnings were in line with internal projections. I understand there is a gap relative to a number of quarterly analyst projections. We don't, as you know, provide quarterly guidance, but I believe that these projections made by a number of you probably did not include the impact of the significant planned coal unit outages that we had in Q1.

And recall that that's a total of three units, each of which is going to be down for roughly a 100 days. Two of which are completed, the third unit started its outage at the end of the third quarter.

Ongoing earnings were primarily impacted by PNM Electric as I've talked about before due to the lack of rate relief and higher operating costs, particularly due to these planned outages at the baseload facilities. And once again, the absence of a fuel clause, along with higher fuel and purchased power costs, significantly impacted the utility.

GAAP earnings were significantly down, mainly due to trading losses at FCP, which were incurred under extremely unusual conditions I guess is the best way to describe it. But it has caused us to exit the speculative trading book at both FCP and EnergyCo.

We also had unrealized mark-to-market losses at EnergyCo that Chuck will touch on, but they are really just associated with the fundamental operating of the business and the gas positions taken.

We further had to write-off about $18.3 million in our New Mexico electric business as a result of the New Mexico rate case order. I continue to believe that those are assets that should be fully recoverable by rates. And in one instance I think the commission agrees with that, but the way they wrote the order did not allow us to keep the asset on the books. It will not impede our attempt and efforts to gain recovery of those costs in the future.

Moving to slide 4, let me just briefly give you a regulatory update. On the electric rate case, you'll recall we received a final order on April 24th. Initially the increase was $35.2 million, but the commission made some subsequent adjustments that have adjusted that down to $34.4 million. More importantly, the upcoming fuel cause hearing on May 15th.

To really quickly recap, we've filed for a joint motion with the IBEW for an emergency fuel clause. This motion had been discussed and drew the support of the New Mexico Attorney General's Office, which serves as the retail consumer advocate in rate case proceedings, as well as our Governor Bill Richardson. There will be some staff testimony given on May 12th as the key persons for this commission staff will be out of the country on May 15th.

One of the positives that I see is that the commission has expressed a desire to possibly rule on the emergency fuel clause on the 15. Now whether that occurs or not, the desire on their part to get a decision out as quickly as possible is a positive.

Even if the fuel relief is granted, though, the spread between the rates established in this case, which is based on 2005 to 2006 costs, and our current cost of providing service, that gap has grown, and it will necessitate a second -- another filing for rate relief probably in Q3. Obviously, we'll apply the learnings that we've had in this case as we develop and file that proceeding.

We're also on track to file a rate case for our TNMP delivery property in Texas. That will also be filed in the third quarter to recover the increased investment in operating costs for that business.

As to our gas operations sale, things are continuing to move along in a reasonable fashion. There is a procedural schedule out, and the slide lists some of the key dates. So I guess they were really included in the news release, but the main point would be that a hearing is now scheduled for the middle of August.

As to the acquisition of Cap Rock Energy, the filings necessary at the FERC and at the Texas PUC have been made, and we have a hearing scheduled in Texas for early June. So those efforts are continuing to move quickly.

I mentioned briefly the major outages moving to slide 5 that we had at some of our coal-fired power plants, and there are really three that are going through major overhauls. Remember, the age of these units. Units 3 and 4 are roughly 28 years old. Units 1 and 2 at San Juan are roughly 33 or 34 years old, and Four Corners is approaching 40 years of age, the two units at Four Corners. They have moved into a point where this kind of significant overhaul rather than just a typical major overhaul, which usually lasts about six to seven weeks. These are 100-day outages roughly.

At San Juan they were also driven by the installation of new environmental control equipment. Both of the San Juan units have now exited those outages and are performing exceptionally well. You can see from the slide that since they have each moved into operation after the outage, they are in excess of 97% equipped with availability factors. This is exceptionally good, but is the kind of performance that up until 2007 we had seen out of these units.

So we are optimistic as to their performance and we expect the same kind of turnaround with Four Corners as one of those two units goes through an extended 100-day outage.

Now not only is the availability of these units improving, but we're also very surprised and pleased with the environmental performance that we're seeing on Units 3 and 4 after the new environmental controls and digital control systems were installed. And you'll recall that this equipment is meant to better control NOx, SOX and Mercury. And we are seeing performance levels well in excess of our targets.

The removal of NOx and SOX. The Mercury piece is just getting started because we needed to make sure we had everything else working well. But clearly we will be freeing up additional SOX allowances for future sales.

Moving to slide 6, let me spend just a moment on FCP. While EBITDA was down for the quarter compared to last year, I still believe that this business is on target to meet its projections for the end of the year. We've seen obviously a very competitive market within ERCOT, and margins have fallen a bit as we projected.

You'll recall that we projected margins to be in the low 20s, and in the first quarter, we saw margins averaging about $21. So it's within the guidance range. We had higher purchase costs because of some adjustments we've made to the way in which we purchase our supply given the increasing congestion issues that we're seeing in the Texas market.

Sales volumes for the first quarter were down because of mild weather. They were down about 4%. Heating degree days were about 13% below in the D-FW area and about 20% below last year in the Houston area.

The good news and the bad news on the customer front is we didn't lose customers as many did, but neither did we gain any. We held our customers constant basically, a slight increase, but we'll basically call it held at constant.

We are seeing some good trends of the movement into single-family homes as we exit some of the apartment market that we had seen growth in last year. So I think that the marketing plans, while they are being realigned because we're basically rephasing what those marketing plans will be to head more toward end of Q2 moving into Q3.

In the Texas market, what we found is that Q3 is really the switching period. This is when customers getting prepared or getting their first bill in the summer are a little shocked, and they start to look around for better deals. Not only is Q3 really the switching period, but it is also the window in which we earn the greatest amount of our earnings. We see 60% to 80% of the earnings of FCP coming in the June through December timeframe.

So, while I expect that we will continue to see margin pressure in Q2, our outlook continues for this business that it will achieve the earnings within the guidance range for 2008 and 2005. Obviously, the trading losses that Chuck will really speak to are a major disappointment to see that happen.

We have gone through a very rigorous review and post-mortem as to what happened, why it happened, how it could've been managed differently and all of those kinds of things. And on that basis, as I said earlier, we've determined that we should exit the proprietary trading business at this stage for both FCP and EnergyCo.

Let me move to EnergyCo, briefly going to slide 7. It's ongoing EBITDA with a little over $15 million, which is a bit higher than our plan for that quarter. It's driven by strong power plant performance, which you can see from the slide, and more obviously giving us more megawatts to sell, as well as better performance of our NOx equipment, where we had increased NOx sales and favorable O&M costs control.

The plants both had strong availability, and we expect to see that continue. So, we have some minor outages on the two operating units, but those are all built into the plan.

The other piece going on in EnergyCo is the construction of Cedar Bayou Unit 4, which is still scheduled to start up in the summer of 2009. All indications it is on schedule and it is on budget. All the major foundations have been placed. The turbines and the generators have been received and placed on their foundations. We're very excited about what the prospects of that unit entering the market are. We believe it will prove again to be a very valuable investment.

We've also within EnergyCo completed all of the ERCOT market system testing to date. This is associated with the move to an older market, and we are on schedule to participate in the real-time market wide test, which is currently scheduled for September. Whether it will stay on that September schedule, we don't know. There are some indications that they are running a bit behind. But we will be on schedule ready to make that new marketplace work.

With that, let me turn it over to Chuck to talk about the specific financial performance.

Chuck Eldred

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% customer growth in colder weather in New Mexico.

When you look at the First Choice, Jeff talked about the impact of the business relative to low margins, customer mix, and so that was down quarter-over-quarter by $0.06. On EnergyCo and Twin Oaks we put that segment together because, if you recall, we had Twin Oaks in the first half of last year. So quarter-over-quarter looking at the impact, having transferred that over to EnergyCo is just a slight reduction of $0.01.

Now let me go to the next slide and discuss more specifically the impacts on PNM Electric. As you can see from the previous slide, there is a $0.35 impact on Electric business. And if you break that down quarter-over-quarter, you can clearly see in the first two items that the scheduled planned outages -- and then I reemphasize these are scheduled planned outages to address the problems that we experienced last year with every intent as we committed to in our prior discussions with the analysts and the efforts of the Company to focus on fixing solutions and problems of the Company.

We have sent the necessary dollars to address the planned outages, and that was $0.25. And if you also take in consideration the higher fuel and purchase costs of $0.07, that's $0.32. And comparing that to quarter-over-quarter of $0.35, we would have been $0.03 back, and if you go down the rest of the numbers, then it comes out to about $0.06 behind quarter-over-quarter when you take that in consideration.

The other aspects, lower operating costs that we picked up $0.02 and operations of the business, and also, with the performance Palo Verde 3, unregulated margins were a slight pickup giving us $0.02. So you can see if you look at the walk across and talk about the impacts relative to PNM Electric, certainly quarter-over-quarter looks really bad.

But when you understand the fact that it is within our expectation, once again it is clearly on our budget and plan of what we're looking for to accomplish in the first quarter. We felt pretty good about the fact that we are moving in the direction that we've committed to fix the problems and look for solutions to improve the performance of the business.

On the next slide, I want to talk about just a reconciliation of the ongoing to GAAP simply because of the significance in the write-offs. I'll talk about the speculative trading in just a minute, and I have a separate slide on that.

But I also want to point out with the final rate orders there were a couple of items that were regulatory disallowances that we had to take a write-off on GAAP. One is the coal mine decommissioning. This is an issue that we had taken up with the commission and still have concern relative to their final order, but it capped us off at $100 million. We disagree with that, and we'll probably seek a rehearing to address that going forward. But that on a pretax basis is about $19.6 million.

The other part of it is the renewable energy certificate credits that we have. Basically in this situation, we will seek recovery of those costs, but given the fact that it's unknown of the amounts to recover and the methodology and what will be ultimately addressed by the commission, from an accounting perspective, we had to go ahead and take the write-off on that. And that's about $10.6 million. And once we know more clearly what the methodology will be of the potential recovery, then we will book that as a regulatory asset going forward in the future.

The other items are some miscellaneous items that really reflect nuclear decommissioning and other mark-to-market hedges that resulted in an additional $0.04 write-off to GAAP.

On the next page, I want to talk about what Jeff referred to, and that's the hard lesson that we learned on the trading position we took at First Choice on a proprietary book that resulted in a significant loss. The best way to explain this thing, if you look at this slide and you see on the history of pre-2008 gives you a perspective of how we saw the market.

And this is something that First Choice had previous positions on that made some slight earnings about anywhere from $2.00 to $4.00 per megawatt hour. And so back in the fourth quarter of 2007, they entered in this position that assuming that the same conditions in the market that had occurred previously would be the conditions going forward. And that would result if things had worked according to plan probably about just a $2 million or $3 million pickup on margin for First Choice.

And some of the major points to talk about in that trading position is, first of all, there was no indication that ERCOT had any transmission constraints in their ability to manage that. There was certainly an understanding that the wind generation in the Western zone was managed effectively by ERCOT. The basis spreads that typically were related to those positions were around $0.50 to $1.50.

And you can see in the right portion of that slide where those basis spreads expanded up to and over $100 per megawatt hour. And it's for that reason that the basis spread differential and the volatility that was created by the fact that the market began in early January when they had this position.

And I want to emphasize that we saw the position and the losses potentially on the forward curve on our risk management metrics and reporting in early January. And, as we saw those positions, we looked at the trading losses, the mark-to-market positions, and we evaluated that.

And at that point we still were convinced that those mark-to-market positions would reverse themselves out and would come back to be positive. We did not see any reason to think that congestion or difficulty was existing within the ERCOT market that would result in anything different.

In fact, on a cash basis, as those positions were settled out in January, it was actually positive. So the forward curve, being that it's illiquid did represent some movements that would show the losses.

Again, let me just point out that our risk management practices allow for a $4 million VAR within First Choice. This VAR calculation for this particular trade was $1.5 million. And because of the VAR calculation covers the 95% confidence level at two standard deviations from the mean, this particular event was actually nine standard deviations away, clearly indicating it was a highly unlikely chance of that ever occurring. But still the risk management picked it up, and the fact that we have another calculation to capture the gross earnings at risk, and that's where we begin to see the potential loss.

As we convinced ourselves that those positions would reverse themselves out, we began to move forward with monitoring the current situation. In February, we began to see again another event that occurred that represented some congestion. Didn't see the physical congestion, but the forward curve began to reflect, and again being illiquid some significant movements that began to show a more significant loss.

At that point, we made the decision to start to exit the transaction, and we did that with an effort to convert those positions to gas with some collars that would protect us on the upside movement of gas, and we began to execute a strategy there to unwind those positions and work ourselves out.

As we saw, 50% of that position was converted to gas. The market moved again. At that point, we decided not to continue the strategy of converting the gas. We went ahead and just made the decision to get out because we couldn't clearly indicate there was any reason to believe at that point these transactions would reverse themselves.

We took the loss at that point, and we're currently in 50% of that transactions and liquid gas positions with collars. The gas prices have to move roughly 20% in order to get any pickup on that mark-to-market loss. Frankly, at this point, we're not seeing market conditions to move in that direction, and so we've begun to execute even the gas positions to flatten that position out and take the loss.

Again, it was a hard lesson to learn, but as Jeff said, we reviewed the circumstances from all aspects of our ability to manage that. We came down to the decision that given the ERCOT market, the volatility and the uncertainty around the congestion issues that wasn't clearly known going into this transaction but seem to be appearing now in 2008, that the right decision was to permanently exit the speculative trading position, as well as permanently exit the speculative positions period within First Choice power.

We also related that onto EnergyCo and made the decision as both partners to address the circumstances and agree that going forward that we would not within EnergyCo have any spec book and would not allow for that operation. They had a slight position of about $2 million. We had 50% of that that they unwound, and going forward there are no positions at EnergyCo on the spec book.

Again, as Jeff pointed out, we've exited the business on both sides. It was an unfortunate circumstance that was unpredicted. It was something that we had been able to be successful that would have contributed a slight benefit to earnings, but the wide swing and basis and the market movements and illiquid position resulted as it did in a significant loss.

Since then, we're taking proactive steps to work with ERCOT. I think there is a number of resources and companies now working with ERCOT to begin to address the transmission constraints and the issues to better understand what that market constraint maybe going forward and how it will be handled by ERCOT.

On the next page, I want to talk about liquidity. There is obviously given the financial distress in the Company and the difficulties the markets had and us having the ability to exit the market to pursue our long-term financing plans, the Company earlier this year began to seek additional credit support to ensure that the liquidity was adequate and supports the Company as it wanted to execute its financing plans.

As a result of that and over the last few months, we had executed and have commitments, as well as facilities in place at PNM for $300 million, which is a bridge capital market facility to backstop any opportunities as we go to the market that we have that facility in place if there are difficulties and challenges within the market.

We're also in the process of closing a $100 million credit facility, which will support margin calls and any support relative to our trading activities within the utility in the event that we have to address support of those margin calls. There is currently today we only have about a little less than $12 million on margin calls for PNM utility, but this backup facility of $100 million will easily cover what we need going forward.

As Jeff pointed out, we also have put in a credit facility in for TNMP. The numbers here show $80 million. We're moving with a recent commitment letter yesterday up to $120 million. We intend to close that down to about 150, possibly even 200. We're working on a number of banks right now.

But the bottomline is the overall capacity that we now have for liquidity is slightly over $1.6 billion, and if you net the available outstanding amounts of the 430 and look at the available liquidity, we're slightly above $700 million. The Company is in very good position on its liquidity front, although we've had difficulties on the financial side with the rating agencies with some uncertainty about the ratings.

You may have seen from the announcement of S&P last night that they have taken further rating action on the Company, which they have held the utility at BB+, moved it from a negative watch up to stable, and they dropped the holding company down to BB minus but a stable outlook.

Given the financing that we're pursuing right now, we've been getting preliminary ratings from Moody's, which they have held to their previous rating position. That is a BAA3 investment grade at the utility, but still on negative watch and a BAA2 on negative watch at the holding company.

With that, we went ahead and announced to the market last night as we released our Q1 that we are going to the market to finance $700 million. That's $350 million at the holding company and $350 million at the utility. Again, with the adequate liquidity that we have in place and the fact that we are using this for corporate purposes and to pay down short-term debt, we feel like the liquidity issue will be solved. And we will be successful in executing the financings that we have that we just entered in the market. And part of that financing, as you recall at the holding company, was the requirement to remarket $247 million of the public equity hits that has to be remarketed from May 9th through the 13th.

So we're on track to doing what we said we were going to do in accomplishing the efforts, although the stress on the Company is still reflected in the lack of support on the regulatory side for PNM utility and still need to have success in the ultimate outcome of the fuel clause. And we have hearings coming up May 15th to begin to address that. And hopefully, we'll continue to have some progress and make some efforts and relief in the commission to have a good rate order and some focus on fuel clause to begin to move the utility back into the financial track that it needs to be on.

So with that, I'll turn it back over to Jeff to talk about 2008 objectives.

Jeff Sterba

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 EnergyCo, but I will reemphasize that our focus with EnergyCo is first to establish and strengthen its presence within the ERCOT market.

On Palo Verde's performance, frankly, we're continuing to see progress made. And we've talked about this a number of times before about how you have a differential curve between how you improve the regulatory safety margin, if you will, and how you improve plant operations and the investment that it takes to doing it.

I think that this is on track. We're showing continued improvement in the performance of the plant and good indications coming out of the discussions with the NRC in terms of where they, particularly at the staff level, believe that the plant is today and where it can be going forward.

I talked about the scheduled environmental upgrades. We're pleased to have them completed on two units. We've got two more units that will still go through it, Units 1 and 2 at San Juan. One of those units is scheduled for this fall, and the other unit is scheduled for next spring. They will not be quite as long outages, partially because they already have digital control systems installed on them. But they will still be significant extended major overhauls, along with the environmental retrofits being installed.

On the O&M reduction, you'll recall that we talked about our plan to be able through efficiency and process improvement to remove about $35 million out of our cost structure. We're on target to achieve that. We've basically achieved about $13 million so far of those savings. So we believe that that is on schedule. And as we move into 2009, we think that we'll see some increase above the $35 million, not enormous, not significant but some increase above the $35 million.

Obviously, the ability to recover the cost of providing service is critical, and we've gone through the schedule to put both New Mexico back on track, as well as the slight under-earning that we're seeing out of our delivery business in Texas.

So with that, I would be happy for our team to take any questions you might have.

Question-and-Answer Session

Operator

(Operator Instructions).

We'll go first to Greg Gordon with Citigroup.

Greg Gordon - 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?

Chuck Eldred

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.

Greg Gordon - Citigroup

Thank you.

Operator

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

Edward Heyn - Catapult

Good morning.

Chuck Eldred

Good morning.

Edward Heyn - Catapult

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?

Jeff Sterba

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.

Edward Heyn - Catapult

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

Jeff Sterba

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.

Edward Heyn - Catapult

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?

Jeff Sterba

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.

Edward Heyn - Catapult

Great. Thanks a lot.

Jeff Sterba

Thank you.

Operator

We'll go next to Paul Fremont with Jefferies.

Paul Fremont - 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?

Jeff Sterba

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.

Charles Kitowski

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.

Paul Fremont - Jefferies

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?

Charles Kitowski

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.

Paul Fremont - Jefferies

Okay.

Jeff Sterba

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.

Paul Fremont - Jefferies

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?

Jeff Sterba

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.

Chuck Eldred

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.

Jeff Sterba

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.

Paul Fremont - Jefferies

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?

Jeff Sterba

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.

Paul Fremont - Jefferies

Okay.

Jeff Sterba

We're well on plan so far this year.

Paul Fremont - Jefferies

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

Jeff Sterba

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

Paul Fremont - Jefferies

Okay. Thank you.

Operator

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

Maurice May - 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?

Jeff Sterba

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

Maurice May - Power Insights

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

Jeff Sterba

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

Maurice May - Power Insights

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.

Jeff Sterba

What's the 1.5 million?

Chuck Eldred

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.

Maurice May - Power Insights

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?

Jeff Sterba

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

Maurice May - Power Insights

The loss for the whole quarter?

Jeff Sterba

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.

Maurice May - Power Insights

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?

Jeff Sterba

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.

Maurice May - Power Insights

Well, good luck.

Jeff Sterba

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.

Maurice May - Power Insights

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

Jeff Sterba

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.

Maurice May - Power Insights

Interesting.

Jeff Sterba

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.

Maurice May - Power Insights

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

Jeff Sterba

On an annualized…

Maurice May - Power Insights

Yes.

Jeff Sterba

Yes.

Maurice May - Power Insights

Still the same?

Jeff Sterba

At this stage, yes.

Maurice May - Power Insights

Yes. Okay. Thanks, Jeff.

Operator

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

Lasan Johong - 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?

Chuck Eldred

That's correct.

Lasan Johong - RBC Capital Markets

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

Chuck Eldred

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

Lasan Johong - RBC Capital Markets

$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…

Chuck Eldred

Yes.

Lasan Johong - RBC Capital Markets

…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?

Jeff Sterba

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.

Lasan Johong - RBC Capital Markets

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?

Jeff Sterba

In my judgment, no.

Lasan Johong - RBC Capital Markets

Okay.

Jeff Sterba

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.

Chuck Eldred

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.

Lasan Johong - RBC Capital Markets

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?

Jeff Sterba

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.

Lasan Johong - RBC Capital Markets

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?

Jeff Sterba

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.

Lasan Johong - RBC Capital Markets

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?

Chuck Eldred

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.

Lasan Johong - RBC Capital Markets

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

Chuck Eldred

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.

Lasan Johong - RBC Capital Markets

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

Jeff Sterba

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.

Jeff Sterba

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

Operator

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

Paul Patterson - Glenrock Associates

Good morning, guys.

Jeff Sterba

Good morning.

Paul Patterson - Glenrock Associates

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?

Charles Kitowski

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.

Paul Patterson - Glenrock Associates

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?

Charles Kitowski

That's a good way to look at it.

Paul Patterson - Glenrock Associates

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?

Jeff Sterba

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.

Paul Patterson - Glenrock Associates

Okay. Thanks a lot guys.

Jeff Sterba

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.

Operator

Thank you, everyone. That does conclude today's conference. You may now disconnect.

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Source: PNM Resources Inc. Q1 2008 Earnings Call Transcript
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