PNM Resources Inc (PNM) 2005 Q2 法說會逐字稿

Good day ladies and gentlemen and welcome to the quarter II 2005 PNM Resources earnings conference call. My name is Anika and I will be your coordinator for today.

[OPERATOR INSTRUCTIONS] We will be facilitating a question and answer session towards the end of today's conference.

As a reminder this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today's call, Lisa Rister, Executive Director of Investor Relations. Please proceed, ma'am.

Thank you very much. Welcome, everyone, thanks for joining us this morning for our second quarter 2005 earnings call.

Please note that the presentation and accompanying materials for this conference call and supporting documents is available on PNM Resources website at www.pnmresources.com. Joining me today are PNM Resources Chairman, President and CEO, Mr. Jeff Sterba and our Chief Financial Officer, John Loyack as well as other members of the PNM Resources management team.

Before I turn the call over to Mr. Sterba I need to remind you that some of the information that we will be providing this morning should be considered forward-looking statements pursuant to the private securities and litigation reform act of 1995. We caution you that all the forward-looking statements are based upon current expectations and estimates and that PNM Resources assumes no obligation to update the information. For detailed discussions of factors affecting PNM Resources results, please refer to our current and future annual reports on form 10K and the quarterly reports on form 10Q as well as our other current and future reports on Form 8K filed with the SEC. With that, I will turn it over to Jeff.

Thanks, Lisa and good morning, folks, it is a pleasure to join you today. I want to particularly welcome the five analysts that are new to covering our stock, we're glad to have you aboard.

The second quarter of 2005 was a period of what I guess I would call mixed results. We had some strong successes in what I think are longer lasting areas for the growth and performance of our company but we also face some disappointments particularly in the generation arena, and I will spend a little bit of time talking about that. On page 3, I will give a very brief second quarter overview and as you know, we released earnings showing ongoing earnings of $0.20 per diluted share compared to $0.28 in Q2 of last year, that brings our year-to-date earnings ongoing to $0.69 compared to $0.68 for the same period last year.

Let me deal with the disappointments first. San Juan plant availability and Palo Verde availability was not up to par in what we expect. We did provide information through the release of 8-K that gave information on some of the situations that we face.

But if you would flip to page 4, you will see a summary that shows the outages that we experienced, color coded to reflect what was forecasted and what had either been postponed or accelerated. In short, at San Juan, we had expected to see what we call an equivalent availability, which is how much could the plant have produced. We expected to see an equivalent availability of about 94% across the plant and we saw about 82, so about 12 percentage points lower than our expectations.

This was largely caused by a situation that occurred at the end of March. I think we talked about it at the first quarter update, in which we had a rupture of a major pipeline -- waterpipe -- into San Juan 4. And the good news of that is that our folks were able to react very quickly and move a scheduled outage on that unit -- that was scheduled for the third quarter of this year -- move it up and take care of it in March and April. So, much of the power that we, in a sense, lost in that period we will pick back up in the third quarter because the unit has already gone through its minor overhaul.

On Palo Verde, we expected to see about an 84% availability and saw an actual availability of about 67%. Unfortunately, on the Palo Verde situations, there is no real makeup that we expect to see through the course of the year. We just ran into some situations that kept its performance from being as we had expected it to be. These predominantly dealt with the need to extend an outage that was originally geared for 36 days. This was a refueling outage as well as some maintenance and then a situation that developed regarding one of the reactor-coolant pumps, where we had a failed seal and it appears we have a manufacturing or installation issue -- the installation instructions from the manufacturer.

Neither of these situations do I read as anything more, at this stage, more than we had poor performance for a quarter. We certainly are going to do what we can to make up for it as we go throughout the year, and as I said, the San Juan performance in the third quarter will be better than we anticipated, but we are not going to be able to make up for the Palo Verde situation.

On the good side, as you all know, we closed the TNP transaction on June 6th. And I will provide a little more color on the TNP transaction. Let me talk to you on a couple of other things that I think have continued to go well. We have continued to see steady growth in our retail electric and our gas customer within New Mexico. The 2% growth that we saw in the second quarter -- July, as it has been the case in most of the country, has been an exceptionally warm period.

We have seen our peak increase by a little over 6%, so we have set a new system peak, and I expect to see kilowatt hour growth in July be similar. And then relative to the TNP transaction, we had indicated to you that we would update our guidance for earnings once we had closed the transaction and then once we had been able to go through our re-forecasting at the second quarter. So I am please for us to have announced a 10% increase in our earnings range for this year from the $1.40 to, $1.55 moving to $1.55 to $1.70.

Let me speak just a little bit about the TNP transaction and if you move to slide 5 -- as you know, we consummated the transaction on June 6th, which was about ten months from the date that we announced the acquisition. We are pleased with the response that we received from the regulatory -- through the regulatory process and the ability to negotiate settlements in both of our state jurisdictions -- obviously get the federal approvals that were necessary.

What, probably, I am more pleased with, though, is the pace at which our integration process is moving. You know, it is always easy to plan savings. The execution of them is what really counts. And I think our integration team has done a superb job of developing an actionable plan and have been, frankly, executing on it for about the last three or four months, some of it not being able to be effectuated until such time as the transaction actually closed.

But the pace of the change that is going through, the attitude of the people, the encompassing nature of the plan that is being executed for the integration of software and systems and the integration of our support service areas, I am, frankly, very pleased with. The synergy savings are on track because of that. As you will recall, we are going to flow back to customers in Texas and New Mexico -- about $25 million of synergy related savings over the next five years, and I fully expect that we will see that amount of money also coming into the shareholders as additional savings caused through the integration of the acquisition.

One of the things we recently noted was that we had filed with the seller of TNP, a purchase price adjustment. Let me just explain briefly what that is. This transaction was not a fixed price transaction. It had what we called a working capital adjustment and its purpose was to allow for adjustments that would happen on the basis of how they -- how their business performed between the time that we entered into the transaction and the time that we were able to close the transaction. So in fact if there was less working capital, less cash in the business, because of mild weather, for example, we would be able to reflect that as an adjustment to the purchase price.

We filed it. We are certainly not going through the details of it in a public way. Just to let you know that we don't expect that we'll have any significant impact and it really is just a little bit of upside -- any significant impact to the transaction and its overall economics. So the TNP transaction we're very pleased with, where we stand in its integration and execution. It contributed to the earnings for the Company for the second quarter and we expect to see that continue obviously as we go forward through the balance of the year and that's the basis for revising the earnings guidance. At this point I would like to go on and turn it over to John to go over in more detail the reconciliation of earnings.

Thanks, Jeff, good morning. Let me start on slide 6 with reconciliation of GAAP to ongoing earnings. For the quarter PNM Resources earned $0.02 on a GAAP basis compared to $0.28 a year ago. Ongoing earnings as Jeff mentioned were down $0.08 to $0.20 for the quarter reflecting the impact of solid fuel generating unit performance in the quarter.

We did have $0.18 of non-recurring items in the quarter, most of which were related to the TNP acquisition. Refinancing costs associated with the TNP acquisition were $0.08. Our acquisition integration costs -- that's severance and relocation, consulting fees, and project costs associated with the synergy savings projects that are going on, of $0.04.

We did have a software write off. This relates to changes in rioles around transaction tagging in our wholesale business that required us to create a new system in the wholesale marketing area. That write off of the old system was $0.04 and then we were required to create a regulatory liability associated with our settlement in New Mexico for the TNP transaction of $0.02.

On a year-to-date basis GAAP earnings were $0.50 versus $0.68 last year. On an ongoing basis earnings were $0.69 up about 2% from a year ago. Again, we saw a good Q1 plan performance in the addition of the TNP transaction, that was only partially offset by second quarter plant performance. Same one-time items to get from GAAP to ongoing. As we see in the second quarter we had no one-time items in the first quarter of 2005 and we also had a no non-recurring items in 2004 at all. Let me also mention on the acquisition integration costs -- we will see those costs continue to trickle through the operations over the next eighteen months as we continue to integrate and complete our merger integration plans for TNP, so expect to see those each quarter as we roll forward.

On slide 7 let me take you through the major drivers, quarter over quarter. Plan availability was about $0.10 of impact. We saw production at our coal and nuclear units down about 9% or 218,000 megawatt hours. This caused about $4 million there of margin (generation) from the Palo Verde outages, a combination of margin, and O&M at San Juan of about $5 million, and $1 million at Four Corners. Purchase power was also higher. We purchased more. Our prices were up 12.6% and we also purchased more under some of our long-term purchase power agreements. They have an average cost of about $40 versus our generating fleet, which is much cheaper than that. On the long-term contract margin, we saw a $0.01 erosion there because of the roll-off of our N-navy contract. That contract is actually coming back to us as part of the rebidding process -- we'll start to serve them again in 2006 but for between now and then, it has a small impact. That was offset by growth in other contracts.

We also saw lower off-system transportation sales on gas of $0.01. We saw actually good basis differentials between Permian and San Juan. But the gas price is so high and the fee to move it is based off the gas price, and that really eroded the opportunity there. On the positive side, we saw an $0.08 improvement because of the TNP acquisition. As Jeff mentioned it is in there for 24 days for the quarter. We saw $0.06 of earnings from First Choice, $0.04 from the utility and that was offset by $0.02 of financing costs associated with the transaction -- that was the common stock we issuedandn the mandatorily convertible securities.

We also saw growth in our retail business in New Mexico. Gas customer growth up over 2%, electric load growth was up about 2% and that increased earnings $0.04.

On a year to date basis on slide 8, you see the impact of plant availability. It is a little lower there because we did have good performance in the first quarter. Weather, which was a first quarter issue that we talked to you the last time we were together -- we had a mild winter heating season. That dampened both gas and electric demand. We also had the effect of the leap year where we lost a billing day this year over last year. That's embedded in that $0.06.

Purchase power costs -- same issue as we discussed in the second quarter and operating expenses up about $0.02. We mentioned to you last year that we expected depreciation would rise a bit as we have had some new system platform investments that are coming on that have fairly short depreciation lives of five years. We're seeing the impact of that. That was offset by improvements in O&M and administrative costs.

On the positives, again, the TNP acquisition addition. Same as the second quarter, same 24 days of activity. Load growth added about $0.08, $3 million of gas margin and $6 million margin of electric margin year-to-date. And, of course, the last quarter of the gas rate increase rolling on, remember, our residential customers didn't come on to new rates until April last year, so we picked up the first quarter of that. That was about $6.7 million in margin or $0.07 of EPS.

On slide 9, before we get into the detail in segment reporting performance, let me walk you through the new segment reporting model now that we've closed the TNP acquisition. Obviously, we're adding the TNP electric business under our regulated activities and First Choice under our unregulated activities. We've also made a few other changes.

Transmission, which we used to break out as a separate business line, we're actually now going to integrate back into the distribution utilities for both TNP as well as PNM. There is just not enough volatility there to continue to break that out. We're also combining forward sales and short term sales on the margin side for the PNM wholesale business. Again, the only volatility we tend to see on the forward side is market to market. We will point that out to you, if there is some. But again, I don't think there is really enough information there to make that a compelling, from a separate reporting perspective. So, those are the changes to the new reporting model.

Let's roll through that on slide 10. We'll start with margin in the second quarter. Overall gross margin was up $10.3 million, 6.6%. $21.4 million of that came from the TNP acquisition and then that was offset by plant performance in the quarter that affected both the PNM utility -- electric utility operations as well as PNM wholesale operation.

PNM electric utility margin was down $3 million, or about $3 million. Plant performance was $7 million of that and that was offset by load growth of 3.4 million and improved transmission margins of $500,000. The gas utility margin was largely flat. We saw customer growth which generated about $1.8 million of incremental margin. But that was offset by lower off-system gas transportation sales. And the addition of the TNP electric business added $12.5 million of margin, to sum up the effect on regulated operations.

On the unregulated side, long-term wholesale was just about flat. We saw the roll off of the Navy deal that we talked about before and that was largely offset by better demand from TNP, Kirtland Air Force Base, our Mesa and Gallup contracts, as well as our Overton contract.

Where you can really see the impact of plant performance is on the short term wholesale activity. We see a $7.3 million decline in margin. San Juan ran at an 82% equivalent availability versus 87 a year ago. Palo Verde, if you remember, didn't have a very good second quarter last year. It was the 74% availability but that dropped to 67% with the outages that Jeff walked you through.

Market prices were actually up $50 around the clock versus $46. But that actually hurt us because of the lack of availability, instead of helping us. We did see velocity drop a little bit, 1.9 versus 2.1, because we just had less activity to market around because of availability out of our core units.

To wrap up the unregulated operations, First Choice for the 24 days, added $8.9 million of margin to the mix.

On slide 11, we can go through the year to date margin performance by platform, total gross margin up $16.9 million, 5.1%, TNP added $21.4 million to that mix. That was partially offset by plant performance in the second quarter, and weather in our legacy businesses in the first quarter.

The PNM electric utilities saw just about a $5 million drop in margin, year-to-date, $8.3 million of that from plant performance, $2.2 million due to weather and the leap year and that was offset by growth of $5.6 million. The PNM gas utility saw a nearly $4 million improvement in margin. We saw the impact of the rate increase in the first quarter as $ 6.7 million, growth another $2.6 million, and that was offset by mild first quarter weather, that was about 4.5 of margin loss and lower off system transportation sales of a million.

The TNP again, same as in the quarter, added $12.5 million on the electric operations that total up the regulated side. On the unregulated side, on the long-term contract component of the PNM wholesale business -- again, just off a little because of the Navy transaction -- on the short term side, again, you can see the impact of the plant performance offset by pretty strong plant performance in the first quarter and then the addition of First Choice.

On slide 12 we'll go through the ongoing earnings by segment. Electric utility earnings on the PNM side down $0.04 to $0.12. Plant availability offset by 2.1% growth. Gas utility earnings were flat, quarter over quarter, customer growth at 2.3%, offset by lower off system sales. And then we saw the addition of TNP for 24 days which added $0.04. On the wholesale side, we were down $0.08 per share to $0.02, plant performance at Palo Verde and San Juan in the quarter. First Choice added $0.06 of earnings and corporate and other was down $0.06. Half of that comes from the dilution from the new securities we issued.

Remember those are all corporate securities, common stock and mandatorily convertible securities, at the holding company. We're also capturing labor and this is about ready to end now that the transaction is closed -- capturing labor for people in the business unit areas that we're working on the transaction, and holding that labor up at the holding company rather than distributing it back to the individual business units, since the transaction didn't affect the daily operations of the current business.

Just to give you a little extra color on the TNP results for the quarter, on a full quarter basis even though they were only in our results for 24 days, TNP utility earnings were up about $0.05 or 55%, to $0.14. Margin was up 5.4% on 1.6% customer growth as well as some increased average use per customer. We also saw some O&M savings come cross in the operations there on a full quarter basis.

For First Choice earnings were down about 2%. We did see some attrition in price-to-beat customers that was partially offset by additional competitive customer additions, but the bigger issue is really some friction between price to beat, which -- and when it was set -- and the continued increase in gas prices. The prior management hadn't hedged their gas portfolio when they re-struck price to beat in May. Gas prices have continued to rise. Not enough to restrike price-to-beat,nso that will erode margin a little bit in that window, and we're seeing the effects of that in the quarter.

On slide 13, the year-to-date earnings performance by segment, PNM electric results were down $0.04, 1.1%. Second quarter plant performance partially offset by growth is what you see there. On the gas utility side it is up $0.04 to $0.16. And that's the impact of the rate increase in growth and a little bit of a decline in our off-system transportation sales. TNMP again adds on the electric business side, $0.04. PNM Wholesale declined $0.04 to $0.13. Plant performance and plant availability was the factor there. First Choice again with the $0.06 addition and the change in corporate and other of $0.05 again relates to the dilution in the capture of labor for the TNP transaction.

So, overall for the first six months of the year $0.69 versus $0.68 a year ago. If we look at the TNP results on a full six month basis the utility earnings were up $0.02 to $0.19 and we are seeing low growth there, a percent and a half, as well as cost control.

First Choice, just to point out, year-to-date is down $0.12. A big chunk of that, over half of it, relates to a one-time item in 2004 where they booked a gain at First Choice for the settlement on purchase power exchanges in (ERCOT). They had been reserving because transactions had a fairly large lag when the market first opened and had enough experience to release that reserve in the first quarter of 2004. Obviously that's not going to recur. They're at the current run rate. Just want to point that out as an unusual item if you're looking at their results on a stand-alone basis.

The issue around customer attrition and, of course friction between price-to-beat -- we had the same issue when they struck in December. Gas prices rose until they struck again in the spring, so the same kind of impact there.

On slide 14 as Jeff mentioned let me restate that we've revised our earnings guidance, $1.55 to $1.70 from $1.40 to $1.55 -- that is up about 10%. Our drivers have changed now that the mix of the business has changed and I think we're starting to see the value of the diversity of having TNP in our mix even for 24 days in this quarter.

Plant availability will always be critical. We saw the value of good plant performance in the first quarter and what happens when plants aren't available in the second. Weather will be important -- that weather now is more diverse. Obviously we have the ERCOT Texas market. We have the summer cooling season there, which can be more extreme. Sometimes it can be a very different weather pattern than we see here in the southwest and of course, our historical Southwest patterns.

Gas costs become important because of price-to-beat and where you strike and how we hedge gas prices going forward for the First Choice business, and always important, is there a market opportunity because of spark spreads in the Southwest or do we have to run gas units to back up for extra capacity for peaking a load as we get into the summer, so gas prices will be important.

Jeff talked about how far along we are on moving on our acquisition synergies. This really replaces our old cost savings sort of initiatives with a an incremental layer of savings that we're chasing, so that will be important. Customer growth and retention -- we always have customer growth and strong customer growth in our regulated service territories that I think -- TNPs regulated operations will compliment that. We saw it in the first half of the year and of course retention in growth in the fIrst Choice business will also be critical.

On slide 15 let me just update you on a couple of other financially related things. Today we are kicking off an expansion of our bank credit facilities. We currently have $700 million in capacity. We're going to take that to $1 billion. In today's bank market, which is very competitive and priced very well we can actually add that capacity at no incremental cost. We're also going to roll the deals to five-year transactions that can be incremented to a seven-year time frame. So we will have plenty of capacity and plenty of stability within our credit facilities.

The refinancing plan for TNP is largely complete. The PIK preferred security the term loan and the senior debt at the TNP Enterprises level has been refinanced. The last piece of the financing plan that will fall into place will be the cascade component of mandatory convertible securities -- that is a hundred million if you remember. We delayed the close on that just because we had a 30 day window before we could refinance and had plenty of liquidity to be able to do it. That should close very shortly.

We've had some staffing changes in the CFO area. One, I know you will be interested in is, we have a new treasurer (Wendy Carlson). She will be joining us from El Paso energy. She has a wealth of transaction experience in the capital markets. I know many of you on the street know her very well and think very highly of her. She will be a great addition to our team. We will miss Terry. He is hard to replace but I think Wendy will be a great addition to the team.

And then, in the spirit of synergies, we are centralizing and integrating our supply chain operation and Tom Olesen from NiSource will be joining us. He was the Vice President of the supply chain there. He will be the same here. Tom led an effort to drive costs out of their supply chain effort that was very successful and we think Tom will be a key ingredient in us driving similar supply chain savings here at PNM.

I mentioned a little bit the diversity of operations. We saw the impact of bringing in earnings from TNP that were much more than the dilution from the securities we had to add in the quarter. I think we will continue to see the value of diversity of operations as the transaction progresses. It is not just an earnings thing. If we look at operating cash flow for the first six months we're at $178 million versus $132 million for the six months last year. Even with the difficult plant performance you can see pretty good growth on that side as well. And then let me wrap up with our website www.pnmresources.com. I think our group has done a good job. We rolled that out in the first quarter. Lots of very good investor information out there if you're looking for something -- I would highly suggest you take a peek at it. We have done some upgrading to adhere in the second quarter. I think you will find it very useful. With that let me hand it back over to Jeff for a conclusion.

Thanks, John, and let me just also add, even though Terry is certainly not leaving us, he is just moving on to another critical roll over our governance and ethics and internal audit responsibilities, but a big thanks to Terry Horn for all the work that he's done, and think about all of the things we've been able to do to our capital structure, and Terry has had his hand in it. Plus he also puts his hand on the golf club maybe a little more. Let me touch on a couple of closing items -- just updates. As you know, one of the things that we did earlier was we filed for a rate increase on our transmission customers at the FERC.

It is not a huge rate proceeding. We filed for about an $8 million increase. Just as an update we did receive the FERC staff top sheets, which is basically when they look at our cost of service, what do they come up with and it's something that is fairly important as we move through this process, and they came in with a top sheet of just around $5 million.

There are clearly some items that -- with which we have a different point of view, for example, return on equity -- they were in the single digits. I don't see that being appropriate nor do I see that being acceptable. But we are in negotiations. I think -- seeing a gap between $5 and $8 million -- I think we can come to some -- something that will work for everybody.

A second thing, which we also disclosed through an 8K, was the filing of our electric supply plan, which we committed ourselves to do within 45 days of the closing of the transaction with TNP. We actually filed it before then, and it was a combined supply filing. How are we going to meet the electric needs of all the New Mexico load, including the TNMP load that is within the state?

It shows us requiring to add 700 plus megawatts over the next eight years or so, and the first resource that we proposed to bring in is an existing unregulated gas unit, the Afton simple cycle, which we propose to add a steam bucket to, and take it to a one-on-one combined cycle configuration. And that would be about 280 megawatts completed within -- by early '07, mid '07, hopefully in time for the system peak. And then, a series of other resources, a biomass facility that we've been working on, probably a little bit of purchase power and then, the need to look at a base load resource which we, at this stage, are calling a generic resource, have not resolved what it would be, where it would be.

We have a little more time to do that because it is really needed at the end of the period.

We hope to have the ability to get a commission ruling by the end of the year. That's not -- that's a fairly aggressive schedule, but there has been a lot of work done in evaluating a whole host of options that emanated from a competitive RFP that was done the end of last year. So, I am hopeful that we'll be keep that on schedule so we can bring the Afton facility reconfigured into the mix.

We will also be refurbishing and rebuilding effectively one of our older gas plants that's located outside of Albuquerque over the next couple of years, as part of that plan, and adding some capacity as a result of that rebuild.

One of the other things I would like to mention without going into great detail, you all can read the rag sheets as well as we can. The Energy Bill that came out of conference on Monday night or Tuesday morning, frankly, I really do believe being fairly heavily involved in it -- it is a Victory. It is a very sound bill for the country. It contains many elements that can help address the growing energy needs and the burgeoning prices and the increasing dependence on foreign supplies. It doesn't solve everything, but it really is a bill that deserves, and I believe will pass, the House today and the Senate tomorrow.

I talked to Joe Barton yesterday and commended him for what he has done. We have worked closely with -- he, more particularly -- we have worked very closely with Jeff Bingeman and Pete Domenici, who represented the D 7 R sides of the Senate in the conference. And if you look at how the electric utility industry came out of this bill, it is in exceptionally strong fashion. Whether you look at what it does to reliability, what it does to the development of future energy resources, the financial aspects of it, in which about -- if you include energy efficiency -- about $10 billion of the $11.5 billion price tag will flow back into the industry.

About $1a billion in demand side, energy efficiency, about $3 billion into coal. The 15-year depreciation for electric transmission property, a whole series of things that guarantees that will be provided relative to the first round of new nuclear facilities. The whole layout of the bill, I think, is a very strong positive for the industry. A lot of tough issues and I think that the industry worked very well through that.

One of the other things that we did advise you of is the partnership gaming order that came out of the FERC at the end of June, effectively clearing us of the investigation that was being done on the partnership gaming emanating from the Enron issues and the California energy crisis.

With that order coming out, we have now been cleared on all outstanding FERC investigations into the California energy crisis and we had been named in the number. We have now been exonerated on all accounts of those. We do have some ongoing persistent, yet without any merit whatsoever, litigation by the California attorney general, and we will duly defend ourselves through that, and then the only remaining issue we really have is a final determination as to who owes who, what.

As I said, the state of California, there is a process to determine what the refund may be to them. We have a claim against the state of California for bills that they hadn't paid. We continue to believe that we are very adequately covered in our reserves for the likely outcomes of that. We don't really see any impact. I think finally that set of issues is coming to a head, geared for resolution. And last as you know, we increased our dividend $0.06. We said we would take a look at it again after the transaction closed. With the $0.06 increase we are now at $0.80 a share, $0.20 a quarter.

If you look at the mid-point of the new range that we have announced today of $1.55 to $1.70 it is at roughly 50% and we have said that we would be guided by a policy. Our board will be guided by a policy of a dividend pay out ratio of 50 to 60% of earnings and so we feel pretty comfortable with being able to sustain our dividend payments with that increase. So, all in all, while the second quarter was not stellar in some fundamental operations, I think particularly the generation performance side, I think on a total basis, it was a very strong quarter, particularly getting the TNP transaction closed in the fashion in which it was, and in the timing in which it was. With that, I'd be happy for us to take any questions that you all may have.

[OPERATOR INSTRUCTIONS]

Our first question comes from the line of Lasan Johong of RBC Capital Markets.

Good morning, everyone, how are you?

Good how about you?

Good thank you. Sounds like the TNP acquisition is a real big winner. According to my calculations if it is $0.08 for the 24 days assuming that's a one month run rate, it would suggest to me that a twelve month number would be $0.96.

That would be very nice. But not correct. They're in -- a little bit like our gas business except in inverse. It is a fundamentally, the --- since they (inaudible) on generation, the distribution side makes money in the summer and tries to save up a nest egg to get through the rest of the months. First Choice will make money hopefully throughout the career but the $0.96 I would say would be way on the high side.

Yes, let me just point out that if we picked a month to close to transaction, June or July would have been the perfect month because, obviously it is summer peak, so in businesses where volume matters, June and July are great months to have as first months for the transaction, but you can certainly look back at TNP's earnings history to get a sense for how that spreads out over a twelve month cycle.

Great. Additionally you've outlined a $50 million synergy program, $40 million from financing, $10 million from essentially IT transactions. But no word on new business opportunities or operational costs synergies. Is there any more we can expect out of the transaction?

Let me step back to your $50 million and go through a little clarification. We had originally anticipated $40 million in financing synergies. Really that's turned out to be about 45 million and that's basically locked in.

We also when we announced the transaction, announced that we expected on a conservative basis to generate $25 million of synergy savings over the five-year period, and as we negotiated with our regulators, we made agreements to flow a portion of those savings back to customers. In reality we think we will end up saving more than that through synergy operating savings.

These are associated with the bringing together of two finance groups, two HR groups, two IT groups, building common systems as opposed to conflicting systems, there is a whole host of things that are being done to generate those synergies, so there are some operating synergies that will flow through to us.

At this stage we haven't given a new overall forecast of what we think will stick through with the company, but it's certainly going to be in excess of what we are flowing back to our customers through the rate agreements that we entered into.

I think we -- out of the $25 million of synergy savings that we originally estimated, the regulatory outcome was that about $17 million of that would be flowed through to customers. And then, as I indicated, that $25 million number is increasing as we dig more and more into the details and it, in fact could be closer to the $40 to $50 million range.

So would you say that the $50 million you had mentioned was not part of the $45 million financing? That is additional?

It is additional.

Which was not public before, if I'm not mistaken?

The $25 million was made public. The additional savings -- we're still in the process of quantifying what those additional levels of savings will be.

You say you think it might be as high as $25 million more.

Yes, but that's really also over a longer period of time and there is some cost that we'll have to spend in order to get that. So, that's not a net number.

I see. I see. Going back to second quarter, just quickly, it is frustrating that given what's happening demographically and in terms of the fundamental supply, that Palo Verde and San Juan had to go through a difficult period. I think we could safely say San Juan is within your control.

Palo Verde is not. Is there something PNM can do to prevent or stall this kind of future forced outages?

Well, we work very closely with APS and Pinnacle, who are the operating agents of the plant. I continue to have confidence in their ability to operate that nuclear facility.

It has been a premiere facility for the last number of years and I expect that it will stay in those ranks. We have all had bumps in the road that come along.

When those bumps in the road happen, what you do is you pay a lot more attention to it and you focus on what could be issues, what could be drivers, what are the kinds of things that ought to be done and that we can help APS with, if any? But we're a very active participant and certainly intend to continue that way.

One always -- we always would love for our car to drive perfectly all the time, and there are times when all of a sudden something goes bump and your muffler falls off or whatever and of course it had nothing to do with your driving of it. It was the damn car's fault. Well, the power plant is something similar.

We have to recognize that they will go through periods when things can go bump in the night. What you do through the QC process and all of your effectiveness work geared around -- and they do a lot of six sigma -- is to help ensure that each one of the things that does go bump is a learning and that you evaluate and have a very strong root cause analysis that they go through.

They evaluate what's the root cause. They ensure that it is fixed and that understanding that root cause, they address the real problem, and make sure that things are put in place from a process side to keep it from recurring again.

So my confidence is still there with APS and the way in which they can operate that facility. But we're going to -- obviously, you know, you start talking to your mechanic a little more when your car doesn't work right and we're going to be talking more with APS to help ensure that the plant gets back to its preeminent capacity.

Our next question is from the line of David Schanzer of Janney Montgomery Scott. Please proceed.

Your increase in administrative and general expenses I assume is mostly associated with the acquisition. I was wondering if there any other items in there that are worth talking about?

The only thing, Dave, we pointed out was a little bit of depreciation. If you looked at A$G on a stand-alone basis and pulled out the merger impact, it is actually down a little bit for the six months.

Good. That's what I wanted to know.

Yeah. So we continue on our trend of being able to beat inflation.

Good. The other thing is, are there any changes in terms of your outcome toward wind power and have there been any notable incidents in the second quarter or developments in the second quarter to talk about?

Well, not with any specificity, David. We continue to believe that the investment that we made with the existing wind facility is proving itself exceptionally valuable. We are looking at additions to the wind portfolio.

We have been limited in adding any additional wind because of the -- it is not just the intermittent nature. It is the swings that wind places on your system. We can see that 200 megawatt wind farm move 90 megawatts in a very, very short period of time and what that means is we have to have another resource that can move with it. Right now that's our coal units. That's not very attractive.

And so as we bring Luna on, then it will become a much more effective swing mechanism and will give us more regulating capability. We are also, as we've announced before, looking at a biomass facility on the renewable front as well as some smaller scale hydro -- smaller scale solar.

One of the elements in the energy bill is a two-year, we hoped for a three-year, but least we have a two-year instead of only a one-year extension in the production tax credit for renewables. That gives some more certainty for the next two year period of time for renewal development and we are going to take a hard look at the security now.

Well, the security hopefully by the end of the week -- first of next week when this bill actually gets in front of the President and it is signed.

Great. Thanks.

Our next question comes from the line of Paul Patterson of Glenrock Associates. Please proceed.

Can you hear me?

Yes, sir.

I wanted to ask you about the TNP First Choice item, and specifically, a little bit, if you could elaborate a little more on the competitive landscape here. It seems that you were saying that margins were coming down because of high gas prices, yet you also indicated there was more customer attrition. I was wondering if you could give us a little more flavor for what's going on there in the competitive basis.

Let me take at least two pieces of that. First, let's talk about the competitive landscape of customer movement. As you know, in none of the territories has the 40% magic mark been hit on the residential side and so there is still the price to beat on the residential side through the end of next year. You do see attrition out of the PTB set of customers, and this is where we strike the price based on the 20 day trailing forward one-year strip for gas.

And the -- so we do see -- all of the utilities are continuing to see attrition. First Choice has had slightly lower attrition rates than most of the other players in the state, but it's still, I think it was probably 7% or so over the last year, that they saw in loss of PTB customers. More customers being picked up on the competitive side however.

There are about, I don't know, twenty reps in the -- operating within Texas. We don't consider them all competitors because the strategy for First Choice is that it is not going after industrial customers or even large scale commercial customers. Its niche is focused on the mid market and the mass market, and within those markets there are clear competitors, certainly TXU and Reliant are within that group that I would call competitors as are GEXA and others. And it is still working out a lot of the issues associated with affinity, marketing relationships and the like.

We have put in, as you know, a brand new team in -- at First Choice. Jeff Shorter and some other folks, Jeff being the President of First Choice who I have a lot of confidence in, and they're putting their arms around a strategy to help that business grow on a profitable basis.

One of the things that happens in the PTB mechanism is because you can strike up when gas prices are at least 5% higher than what they were the last time you struck, and the -- what you're striking on is, I believe it is a 20 day rolling average of the forward one year strip gas price. When you strike at that point, then the question is what does gas price do? Where does it move after that? And if you're in an unhedged position, the worst situation would be that gas prices move up to 4.99%.

Right.

Above, right, so you're just under where you can strike again and you were unhedged . What we found with TNP, I mean First Choice, I am sorry, is they had not hedged the same way we would have, and we couldn't get -- we can't run their business prior to our acquisition of that. We certainly encouraged them to do certain things.

Even if we suggest it, how they might do it.

Yes, but they had to run the business because you didn't know when it was going to close. So they took a little different strategy than we would have taken and frankly, we are taking today.

I hear you. Let me ask you this. How many customers, what was the attrition rate for the quarter, I guess.

I don't have quarterly data and we typically wouldn't give that out. I think I do have year over year, and I think it is about a 7% attrition.

7% versus what you guys had in the first half of 2004 -- is that correct.

That's correct.

And that's price to beat customers only?

That is price-to-beat customers only. We have more competitive customers than we did last year.

Right. Okay.

And what's driving that I guess is just the same factors that drove it before, we're not dealing with additional advertising or there is no -- because it sounds like the margins for your competitors as well as for yourself have been recently contracting a little bit because of the gas price, but there are still customers leaving because, I guess, there is enough margin to get them to leave, to get the competitors to take them away, is that basically it?

Yes, what will happen is a competitor will run a big advertising program and it will attract away a few customers, and what has happened in First Choice, frankly, is that over the last year, they have not gone after the customers in the same way. What the prior management of First Choice did is they contracted and backed off from any marketing campaigns, so we're obviously going to take a different tact in terms of how we attract. I honestly don't expect do see us on CNN news. We're not going to be advertising there.

We so not believe the kind of effective advertising to attract customers in Texas on Fox News for that matter, if you are of that political persuasion. But you will see us being more aggressive in the targeted attraction of customers in Texas that we believe we can make money on.

Your next question comes from the line of Steven Rountos of Talon Capital. Please proceed.

Good morning, everyone. I guess I had a follow up question to Paul's on First Choice. Is it possible to give us a walk through between the second quarter of last year and the second quarter this year? I know there were some things that obviously would have impacted one way or the other.

I think there were some gas hedges last year, some power purchase hedges that I don't think are there this year, and then maybe the bad debt load -- bad debt that you mentioned on First Choice as well. And any other impact that might have happened year-over-year if you can, kind of, quantify those and walk us from one to the other?

Sure. For the quarter on a margin basis, we saw margin decline $1.7 million to just a little bit over $24 million.

Again, the big component of that was the friction between price to beat and the gas price, because we almost added as much on the competitive side of the customer base as we lost on the price to beat side of the customer base, despite the fact that there was no systematic marketing program in place for First Choice for the quarter. On an earnings basis with the $0.02 decline, the margin probably would have been around -- would have caused about a $0.03 decline.

They picked a penny back up because bad debts was just a little under a million dollars better, quarter over quarter, than it was a year ago and the Company recently added some resources in the credit collections area -- Chris Crabtree and his folks and they've done a great job of tightening down on the credit process and we're seeing the that and we would expect that to continue.

Great. And in terms of the margin -- (the margin is lower) by about $0.03, but was there an impact year-over-year between the hedges First Choice had last year on the gas and power side and where you were -- and where they were this year?

I think the impact is, being hedged versus being unhedged.

But there is no earnings impact from them being hedged last year to being unhedged this year?

Yes. In fact, it is most of that margin change that you see.

$0.03?

Where they had locked in a price to beat and hedged and were able to maintain a margin. This year they set a price to beat and didn't hedge and as gas prices continued to rise, we saw some erosion there.

There was only $0.03, and only, like $2 or $3 million.

Right, not a big impact.

Because it was all offset by price to beat increases? Is that right?

No, price to beat -- well, yes, okay, you mean the actual price to beat itself?

Yes.

Yes.

Okay. Great. And then I guess a follow up on a question earlier, about the cost savings. You say you're looking at cost savings now in the $25 sorry, ahead of the $25 million that you originally had forecasted and originally that was $25 million over a five year period?

Right.

And now you're looking at 40 plus?

Yeah, but one of the things you have to understand -- this is where we'll come back with more analysis for you all.

Some of that is going to require additional investment and so it is not -- you can't take the new number and say that's all going to be -- that's all going to flow through. There are some costs, both operating and capital costs that will be incurred in achieving those.

I see. -- to achieve those cost savings. And, I guess, on top of that you have got some rates, as you pointed out, some rate give backs -- are you giving some back -- some of the cost savings back to customers --

Absolutely.

-- in future years. What are the amounts of those rate give backs in your jurisdiction?

Well, in total and this includes all -- what we negotiated in both Texas and New Mexico were rate paths.

And they vary. And they include both the flow back of synergies, the recognition that TNP was over-earning in both Texas and New Mexico within its existing element, and the recognition that our wholesale contract, PNMs wholesale contract to TNP -- TNMP in New Mexico -- was expiring in '06 and effectively now we would be continuing to serve it, but we would be doing it on a cost of service basis. But total revenue reductions, if you will, or reductions in customer bills, amounts to about $90 million over the five years. Some of that, though is really reductions that would have occurred anyway, for example, the move to the -- to a cost-based purchase, and certainly in a different marketplace, for the replacement contract to the TNMP New Mexico load.

The total synergy savings I believe is about $17, $17.5 million that's flowing back to customers in Texas and New Mexico. Out of the originally estimated $25 million. We believe that the $25 million is going to grow but we don't have a number that's net for you of what we're going to -- of the cost to achieve.

Next question comes from the line of Ali Agha of Wells Fargo Securities. Please proceed.

Thank you and good morning.

Good morning.

I wanted to clarify, Jeff, I think a point you'd made earlier in your opening comments.

When we look at that $0.16 loss that you took in the quarter for planned outages, high power purchase cost, et cetera I think you had mentioned you were planning to capture some of that from, at least, the San Juan unit going forward, so as we look at it for the year, how much of that should we expect comes back as we go forward?

We're going to avoid a three-week -- is that right, Hugh, a three-week outage on unit 4, and that should be roughly $0.05 of value.

And just to clarify, Jeff mentioned picking that up in the third quarter. The outage is really in the fourth quarter. I know everybody is tuning their models quarter to quarter, so.

It is October.

It is an October outage so expect to see that hit fourth quarter results.

Okay.

So, if my math is right, net net, these unplanned outages for the year hurt you by say $10 or $0.11, you picked up about $0.08 just for less than a month of TNP, but your guidance has only gone up by $0.15 and you have got the best summer months yet to come -- summer months -- for your TNP acquisition as well, so is that some other moving parts I am missing, because the net $0.15 addition looks a little low here?

Well remember in our core operations we have the last phase of the electric rate reduction that goes in in September, so we'll get four months of effect from that, which will reduce utility results going forward, and obviously we've had to make assumptions around plant availability for the remainder of the year and all of that.

We also Ali, one of the things that does affect us is -- gas prices obviously this year are higher than we certainly anticipated earlier last year, and that increase in gas price, while we can stop making a sale on the wholesale market if we can't clear our margin, we don't have that ability on the retail side. And since we operate without a fuel clause, at this stage, given higher gas prices, that cuts our margin on retail sales automatically.

Now we don't use a tremendous amount of gas to serve our retail load, and -- but its use is not just triggered when a San Juan or a Palo Verde unit is down. We do burn a couple of percent of our fuel mix in gas, regardless, and it is by and large triggered by loads -- and for example if we look at July, where we've seen about a 6% increase, 6.5% increase in our peak, our system peak, we're having to generate gas to match that and, at the gas prices they are today, we're not making money when we sell that incremental retail kilowatt hour.

Your next question from the line of Maurice May of Power Insights. Please proceed.

Yes, good morning, gentlemen. First of all I want to thank you for the excellent guidance you gave us on the plant operations through the quarter. I wish other companies would do as well.

Thank you.

My question has to do with the Energy Bill. Just wondering what direct benefits may accrue to PNM due to the bill?

Well, there are a series of things. Number one, tax depreciation rates will change for our transmission system, from a 20-year depreciable life to a 15-year depreciable life. There are elements built into the bill that, if we were to go forward with certain kinds of generation development or carbon sequestration, there will be opportunities to participate in federal funding.

I think from a reliability side, the mandatory reliability language that was passed creating an ERO, when is an electric reliability organization -- that NERC will effectively fulfill -- provides greater benefits over the long run. I think another one is the repeal of PUCHA which I have strongly supported. There are a few trade-offs that we have in it, and that the FERC will now have review of generation acquisitions in sales.

But the repeal of PUCHA, I believe, will allow other capital to flow into the market now. Does that benefit us directly? Well, yes, we are a registered holding company. So if this bill goes into law down the road a lot of the limitations -- or not even really limitation, they are issues -- and there are also some capital issues, reporting requirements and the like -- an issue, for example of, do we have to have a services company, in the future, in the costs associated with managing a separate company? That will be able to be taken a look at.

There are additional incentives for the two-year extension of the renewable production credit -- provides more stability in looking -- in us looking at whether we're going to acquire, in the near term, additional renewables. For example, the biomass facility we're looking at, would not come on line for a number of years. It would take quite some time to finish the planning on it and then to construct and operate it. So it may be five years down the road.

But taking a look at expansion of our wind operations, we could do relatively quickly and having the security of the PTC will give us a little more reason to take a look at it. So I think there are a lot of benefits for the industry and I think a number of those benefits directly impact us and benefit us.

Okay. Good. Thank you very much.

Your next question comes from the line of Paul Fremont of Jefferies. Please proceed.

Thank you. I am just trying to better understand the change in business practices, if there was any, at First Choice. In the prior year the practice of First Choice management had been to essentially lock in a certain amount of power and a certain amount of gas in anticipation of fulfilling your obligation for the year under the price to beat.

What would have caused -- first of all, did they not hedge this year as compared to last year, any power or any gas? I guess that would be the first question.

No, they did hedge gas. They just -- we are still trying to understand what their theory and philosophy was in hedging, and I must say that it has escaped, us to some degree.

They did hedge some. It is not like they were operating completely unhedged. They just were not as fully hedged and didn't take advantage of certain points, when we would have put on hedges, to put on hedges. They're not -- it's not like they were fully hedged last year and they are completely unhedged this year.

It is really more that the percent to which they were hedged and the prices that they locked into were not as favorable in '05 as they were in '04.

That makes perfect sense but then, this year as well as last year, there is a specific benefit that the company would have recognized as the price-to-beat levels increased over the course of the year, and can you just remind us of roughly when the -- when price-to-beat increases occurred and the order of magnitude as they occurred for -- within the service territory?

Yeah, December -- it was the first of December, and then I can't remember when in May. They were both at the 5% trigger and I think the last strike was somewhere around$7.95. I think it was just under $8 or slightly under $8. And obviously we've seen gas forwards today that are in the well, as high as $8.23, $8.25, $8.30, and I think today they are in the $8.17 or something like that.

If you start at the beginning of the year or late last year, they would have been locking in gas presumably roughly $1 lower than what they're currently recognizing as part of the price-to-beat and that is benefiting their result.

Yes, the problem, Paul, is that they don't lock in using a one-year strip. They lock in on shorter time frames, so effectively what happened is they were locking in up, as the price curve moved up, so they weren't able to lock -- for example, if you go back to February, prices ran in the $6.25 range, maybe a little lower than that.

They didn't lock in gas for the next twelve months at that$6 six, $6.25 strip price. They would have locked in gas for the next thirty to sixty days at that -- at the price then and then a month later they would have locked in for another two months, okay, so they moved themselves up the price curve.

Okay. Just to sort of clarify, then, at least a portion of what we're seeing in First Choices business this year is a reflection of commodity prices being higher than the hedge price?

That's correct.

Thank you.

Our next question comes from the line of Brooke Glenn Mullin of JP Morgan. Please proceed.

Yes. Good morning.

Good morning, Brooke

First Choice had pretty strong June results. Can you just give us a little more detail about what your assumptions are for the rest the year? And I guess we've talked generally about what First Choice had done with hedging.

Can you talk a little bit more about what your flexibility is on hedging, going forward?

Well we have developed and implemented a risk management policy for First Choice in terms of what exposures we'll take, and it is moving to an earnings at risk kind of approach and they have a series of indices on both VaR and earnings at risk, and then credit support that they are working within. You know, I think the First Choice situation is one where they are -- we're move -- First Choice is already moving into managing this in a very different way.

For example, we did participate in the capacity auctions that were held to auction off Texas Genco and TXU capacity for the balance of the year. That's the first time in First Choices history they've ever done that. So in one sense we will certainly be willing to take on more risk but it's going to be exceptionally well managed risk.

We are continuing to work with the current supplier that has the contract to serve the requirements of TNP or I am sorry, First Choice, that being Constellation and those discussions go on well and we're also staying in contact with other players within that market.

I think what we see is -- we look for, let's say, the balance of this year is that we'll continue to see some attrition in the-price to-beat.

We don't expect it to escalate and in fact we are going to do things-- are in the process of implementing some things to help retard the rate of attrition of the (PTB) side. And we are going to move back into being an aggressive targeted marketer, once we understand the customers a little better, and I think one of the things we realized is that TNP First Choice really did not have a good handle on their customers. Who they were, what their patterns were, how you build affinity relationships within different groups and the folks that we have running First Choice are much more geared toward understanding that better, so I would expect to see not immediately, but six months to a year from now, a reasonable increase in our competitive customers acquisition with good locked in margins.

As we told you earlier, one of our major focuses in -- upon acquisition would be on the supply side, and that's where an awful lot of the energy is being placed, so what can we do to reduce the cost of supply for the customers that we have today, and that work is ongoing and we don't have anything substantive to report to you at this point.

If we look at the actual earnings guidance that was given for the year, can we -- is it possible a sense of whether the assumption is that First Choice is a profitable business, or break even business, going forward.

Profitable.

Okay.

And we used reasonably conservative assumptions when we first looked at First Choice.

I would say as we've gotten into it we've had surprises about some things that weren't done in the past that we just kind of assumed had to be being done and they weren't and so we're having to start from probably a little farther back than we would have liked with First Choice, but certainly it is contributing to the margin. Margin and net profit.

And lastly, if we see that situation where gas prices remain high but not high enough to go in for another price to beat, would that hold true? In terms of it being profitable? Or is one of your assumptions on the guidance that you will have the opportunity to file for another price to beat increase?

No, we have not assumed an increase in the strike. We have not assumed that we strike again.

We have made an assumption that gas prices are a little higher certainly than the current strike but not sitting right under the 5% threshold and in that scenario it makes money. There is a stress test that we've done, Brooke, and I am trying to remember -- my recollection is that if even if we sat a penny under the strike price, that the business still makes money for this year.

Great. Thank you.

Next question comes from the line of Jennifer Preller of Barclay’s. Please proceed.

I know you mentioned on the call the refinancing plan was complete. We're wondering if you're planning on refinancing any of the Texas New Mexico power debt, the '08 or '09.

We are taking a very hard look at those securities and how to restructure them. I won't say that we're -- we're planning to refinance them tomorrow but it is certainly on our radar screen.

Okay. Terrific. Thank you.

Our next question is from the line of Michael J. Lapides of Hibernia. Please proceed.

One easy question, strategically when you think about First Choice, cash cow business or growth business?

I am not sure I would call it a cash cow, and it's growth potential is one we're still really focused on and better understanding.

I think it can be a growth business, the degree of that growth is what we are really working on today. Remember that one of the major reasons for the First Choice acquisition was that it provides a load which is an important component of us developing a wholesale strategy in a marketplace. We will not go into a market naked.

We will not go into public naked, either.

We won't go into the market naked and take a position in assets without having a load to offset it. What effectively having First Choice does is it gives us a load for which we can then look at building a resource base around. That resource base can be used to help meet the needs at transfer price to the REP as well as building a wholesale presence within that marketplace.

At this stage First Choice can either be long-term transitional to get us to a point of establishing our presence in that market or still become part of our core long-term business. We don't have to make that decision today.

The other thing about First Choice is it is not a very capital intensive business at least the REP business as it exists today, so to the extent it is profitable it is generating (very) cash flow because there is really no CapEx going back into that business, of any magnitude, so in that sense it is a cash oriented business.

At this time gentlemen no further questions. I would like to turn the call over to Mr. Sterba for closing remarks.

Thank you for joining us today. It has been in my judgment a good quarter even though the financial results were not as strong as we would have liked. We'll certainly be providing more information as we move through.

Okay.

Hello? Through the third and fourth quarters.

Yes. I am sorry,.

Okay. Through the third and fourth quarters and again thanks for joining us.

Once again ladies and gentlemen we thank you for your participation in today's conference. This concludes today's presentation.