TXNM Energy Inc (TXNM) 2004 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the PNM Resources fourth quarter 2004 earnings conference call.

(OPERATOR INSTRUCTIONS)

I would now like to turn the conference over to your host for today's call, Ms. Lisa Rister, executive director of investor services. Please proceed, ma'am.

Thank you. Good morning, everyone. Thanks for joining us this morning for PNM Resources' fourth quarter and year-end 2004 earnings call. Please note that the presentation accompanying this conference call, together with the supporting documents relating to our fourth quarter earnings, is available on the PNM Website at pnm.com. With me today is PNM Resources Chairman and President and CEO, Jeff Sterba, and Chief Financial Officer, John Loyack, and other members of the PNM management team.

Before I turn the call over to Jeff, I need to remind you that some of the information we'll be providing to you this morning should be considered forward-looking statements pursuant to the Private Securities Litigation Reform Act of 1995. We caution you that all forward-looking statement are based on current expectations and estimates and that PNM Resources assumes no obligation to update this information. For a detailed discussion of the factors affecting PNM Resources' results, please see our current and future annual reports on Form 10-K and quarterly reports on Form 10-Q and other current and future reports on Form 8-K filed with the SEC.

Thank you for joining us and now I'll turn it over to Jeff.

Thanks, Lisa, and good morning to all of you and thanks for joining us today. 2004 was a very strong and good year for our company and we're very pleased with the results that we had. In the fourth quarter -- and I will be using the slides which are available to you on the Website and I'll be starting on page 3. The fourth quarter earnings were 30 cents per diluted share, which is up 36% from the same period in 2003, and there were no one-time charges or gains. For the year, the earnings level was $1.43 per diluted share, or up 10% from 2003, again with no one-time charges or gains.

It was really a series of reasons that drove these results and let me touch on four and I'll go into a few of them in a little more detail. But first, certainly, was the increased gas margin due to the gas rate increase and customer growth. Recall that the gas rate increase went into full effect in April, so we did not pick up the value in the end of the winter of '03/'04 from the rate increase for the large bulk of our commercial and residential customers. But it is now in effect and so we saw it in November and December. The second, we continued to see good retail electric growth. On a weather normalized basis it was about 3.3%.

And one thing I want to spend a little more time on was very good performance at our San Juan plant and at the mine. Moving on to page 4, let me spend a minute on San Juan and its performance. It really was a great year for San Juan with almost a 90% equivalent availability, almost a 6% equivalent forced outage rate, it was the highest level of generation we've ever gotten out of San Juan in its roughly 30 year history, and it broke or tied or came in second on a number of records that we care about from plant safety on down the list. It was a good strong year and I'm very proud of the folks that have helped that plant reach that level of performance.

And I think the mine also had an exceptionally strong year. It was a record year. Production was 7.8 million tons. About 7 million were burned, so we increased the stockpile about 800,000. We're almost on track to the stockpile that we want to have. If you recall, because we're going to an underground source, we have strategically increased the size of the stockpile because there are obviously additional risks that can close an underground mine that you don't really face in a strip operation.

And in '03 we had dipped down to where we had some concern, frankly, about the size of the stockpile. We still had plenty of coal, but if something had happened, we could have been in a position of being a little low. And now we've rebuilt that stockpile up to a comfortable level. We'll probably add a couple more hundred thousand tons to the pile through the early part of this year.

Not only was it a very strong year for production at the mine, but it also -- we ended up with very good quality coal. I think we're seeing the kinds of quality that we expected and that, along with the production performance, has helped us get down to the targets that we had originally established when we embarked on this approach of going underground for coal costs and hit a record low of $1.48 per million BTUs for the average of last year.

Let me move to an update on our proposed acquisition of TNP Enterprises. As you probably know, we issued a release a while ago. We have entered into a settlement in Texas. That settlement has been certified by the Hearing Examiner to the Commission without a hearing being held, and so we're looking forward to reasonably speedy action on the part of the Texas Commission.

At this time it is unopposed and the record has been closed so there's no further opposition that could occur. Recall that when we announced this transaction, we indicated that in the pricing for what we paid for TNP Enterprises, we looked at a variety of cases and sensitivities and I would just say that the agreement that we reached in Texas is well within the boundary conditions that we established in that pricing. So this is a good settlement. It does provide a rate reduction. Recall that TNP Enterprises had disclosed that it was over-earning to the tune of about a 22% return on equity for calendar year '03.

And so we're pleased with the settlement. It was a good collaborative effort with folks that we did not know and I would also recognize the good work that was done by TNP Enterprises in helping with that settlement, which will provide a $13 million rate reduction for the next 2 years, as well as some synergy savings. While we talk about 2 years, let me just note that it really is more like 3 to 3.5 because the way the stipulation is written, no one can file, either the company or interveners can file for rate increase or request a rate review within that 2 year window. So the clock starts at the end of 2 years. That's when you'll then go through the development of a test year, the filing of a case and the litigation of that case. So it really is more like 3 to 3.5 years that we would expect these rates to be in place.

In New Mexico we are currently in settlement negotiations. I really can't say much more than that other than I would indicate that I think we are optimistic that an acceptable outcome will be reached. We'll certainly let you know as soon as that has occurred. We have completed the Hart-Scott-Rodino review and the waiting period has expired, so we're in good shape on the antitrust side. And we have both our FERC and SEC approvals pending in front of the respective organizations. I'd indicate -- I would note that certainly the New Mexico Commission has indicated that they won't issue a final order -- we would not expect them to -- until the FERC decision is out and I frankly don't see any difficulty with that approach.

Just a couple of other updates, first relative to the Luna plant acquisition. The project is on schedule. We have selected a construction contractor that we're in negotiations with. On the basis of where those negotiations stand, for PNM alone we think that the cost will be at least $10 million lower than we had originally announced for the completion of construction, so that would be $30 million total for the project.

And the last item I'd note is we have talked from time to time about our transmission rate levels and the intention on our part to have a review done with the FERC of those rates. We do anticipate filing a transmission rate case in the next couple of weeks or so.

With that, just summarize 2004. When we announced the stock split, we gave an updated range for our earnings for 2004 of between $1.35 and $1.45, which was a slight increase from what we had originally announced at the beginning of the year. And I'm pleased to see that our earnings for 2004 came in at the high end at $1.43 per share diluted.

With that, let me turn it over to John Loyack to go over the fourth quarter and the year in summary.

Thanks, Jeff, and good morning. Let me start on slide 8 with an overview of the fourth quarter and full year 2004 results.

Ongoing EPS was up 8 cents, or 36%, to 30 cents a share in the quarter. We've reported earnings growth now 7 out of the last 8 quarters and that dates back to January 2003 when we first entered into the Global Electric settlement. On a year to date basis, ongoing EPS was up 10%, well above our targeted 5 to 6% growth per year, at $1.43. We had no one-time items in 2004, but if you remember, we did have several in 2003. The first was a transition cost write-off and that was associated with our Global Electric settlement that went into effect in January 2003. That resulted in a charge of 16 cents. We had loss on required debt from refinancing activities that was a charge of 17 cents. We also adopted FASB 143, which generated a cumulative effect gain of 62 cents, and a change in pension accounting that generated a charge of 1 cent. So that walks you through the $1.58 of GAAP earnings versus the $1.30 of ongoing earnings from 2003.

On slide 9 let me walk through the fourth quarter of 2004 results. Again, results were up 8 cents; 16 cents came from margin improvements, which we'll walk through in detail, and that was partially offset by higher costs of about 8 cents. We saw the gas rate increase add 6 million in margin and 6 cents to the bottom line. The load growth added about 4 cents; 3 cents on the electric side and a penny on the gas side.

Plant performance at San Juan added 3 cents. San Juan's output was up 245,000-megawatt hours from a year ago. Plant availability for the quarter was at 92.1% and that combined with the price per ton of coal going down 17% for the quarter. Very strong performance for the plant. Weather added 2 cents. If you remember, in 2003 we had a relatively warm start to the winter heating season. This year we're right on average, 10-year average of heating degree days. That added 2 cents. Long-term margin was up about a penny as we saw the addition of our new Mesa contract and some of the other long-term sales contracts that were ramping up as they're full requirements contracts.

On the cost increase side, we saw higher purchase power cost, some of that coming from higher purchase power as a result of price increases on long term purchase agreements, as well as higher spot prices in the fourth quarter. Remember, Palo Verde had an extended outage well beyond its planned outage cycle. And, in fact, Palo Verde only had a 72% availability factor in the fourth quarter, so where we were buying power, we were doing it at a higher price. We also saw a 4-cent increase in operating cost. 2 cents of that was due to the extended outage at Palo Verde and then we had a penny due to higher bonus compensation, as well as some cost associated with TNP that wouldn't be capitalizable under GAAP rules of another penny. Without those items, operating costs would have been flat for the quarter.

On slide 10 let me take a minute to walk though the segment earnings per share. The electric utility earnings were up 7 cents for the quarter. And again there, load growth, San Juan performance, coal performance and cost control led to that. In fact, if you look at San Juan on a cost per megawatt hour basis, it improved about 15% for the quarter. The gas utility earnings were up about 11 cents. The rate increase, return to average weather patterns and customer growth contributed to that improvement. Transmission was flat year over year. On the wholesale side we saw a 5 cent decline. The extended Palo Verde outage affected results. We're also seeing the continued shift to retail demand of the resource fleet and we also saw some lower rates on one of our major wholesale contracts with Kirtland Air Force Base as they moved from a retail rate structure to a wholesale rate structure this year.

On the corporate side, corporate costs were up. We had the TNP cost that we mentioned. We're also accumulating all of the labor for the organization for the work that's going into the TNP acquisition because at this point, until the deal closes, we don't have an entity to distribute those labor dollars to, so that's in that pot. We also had some higher 401K costs due to some plan enhancements that also contributed to that increase.

On slide 11 if we look at margin by platform for the quarter, margin was up 8.4% on a consolidated basis, largely due to higher utility margins. The electric utility margin was up about 7.5%, $6.2 million. Load growth at 2.1% for the quarter added $3 million of that and then San Juan and coal performance added the other $3 million. The gas utility margins were up 28.3%, or about 10 million. We saw $3 million from the heating degree day change. We had 1713 this year versus 1529 a year ago. The rate case added $6 million and customer growth added another million. And transmission margins were flat quarter over quarter.

On the wholesale side we saw continued growth in the long-term business. Remember, our long-term business represents contracts that range from a year to 16 years in life and have an average duration of about 7.1 years. The growth in the long-term side came from our Mesa contract, as well as growth in our TNP contract, Kirtland and our Gallup contracts. And again, that was partially offset by the pricing on the Kirtland agreement. Forward and short-term sales activity were down about $4.3 million. Again, more power usage by the retail utility, as well as the Palo Verde outage, had a significant impact. That was offset a bit by the fact we did see better prices in the quarter, but again, because of the Palo Verde outage, we didn't fully realize the potential of that. But power prices were about $48, a little over $48 for the quarter versus $37 a year ago.

And velocity was also down a little bit, 1.6 versus 2.3 a year ago. We had some transmission disruptions at our Blackwater converter as well as our Tyeband Mesa transmission facility. And we also saw spreads decline a bit between Palo Verde and Mead, which also contributed to the decline in forward and short-term sales.

On slide 12 let me take you through the full year results. Again, we saw 13-cent earnings improvement, 10% for the year. Margin and interest savings added about 68 cents and the electric rate reduction and higher cost ate into that about 55 cents. Low growth added 24 cents a share, 21 of that coming from the electric utility and 3 from gas. That refinancing activities, remember, we refinanced our senior unsecured notes and some tax-exempt debt a year ago and we also had lower short-term borrowings. That added 15 cents.

The gas rate increase added 12 cents, $12 million to margin, and San Juan performance added 10 cents, with availability near 90% versus 82 a year ago, and lower coal costs. Long-term margin also expanded about 7 cents with new sales and expansion under existing contracts.

These improvements were offset by the electric rate reduction, which reduced electric retail margins by about $17 million. Purchase power costs were $11 million higher; again higher prices under long term sales, as well as higher spot prices. The other for 7 cents represents 4 cents of coal mine reclamation amortization. Remember, as part of the Global Electric settlement, we're amortizing costs associated with going underground. That hit for a full year for the first time this year and that's the impact. We also had a slightly higher effective tax rate.

Palo Verde performance, because of the spring and unplanned outages, as well as the extended fall outage, cost us about 6 cents. Weather cost us 4 cents, 7 cents on the electric side. Remember, we had a very hot summer in 2003 and had an average summer in 2004. And that was partially offset by a 3-cent improvement in weather because the gas business had a normal heating season throughout the entire year. Operating costs were up 4 cents; Palo Verde's unplanned outages were 3 of that, TNP costs that we are not capitalizing were another penny. Transmission margin was down 4 cents due to less demand. And remember, in the third quarter we talked about an energy imbalance settlement that won't recur for one of our transmission providers who also provided us some generation and we needed to reimburse them for that generation.

On slide 13 I'm going to skip through that because I think the walk across in the margin discussion on the next page will cover that. But we did provide EPS by business segment. On slide 14 for the full year margin performance, we saw overall margin of $6.5 million, or 10%. Again, retail utility growth was the key driver. Electric utility margins were up slightly. We saw 3.3% load growth that added about $21 million. San Juan performance also added to that. And the offsets against that were the electric rate reduction, which cost us $17 million, and the return to more normal summer weather, which reduced margins about $7 million. On the gas utility side, margin was up 13.7%, or almost $18 million. The rate improvement was $12 million of that growth accounted for $3 million and a normal heating season added $3 million more to that. Transmission margins down about $3.5 million, again, less third party demand there.

On the wholesale operations we saw long-term sales grow about 7.7%, $6.6 million. Again, the Mesa deal, as well as growth in our Navapache, Kirtland and Overton load were the drivers. Again, the lower Kirtland price down about 20% from the retail rate versus wholesale rate was a mild offset to that. Forwards and short term were down about $15.5 million, again, the shift of resources to our retail jurisdictional business, as well as the Palo Verde outages, had a significant impact on that. Year over year power prices around the clock were up slightly, $45 versus $43. And our velocity was healthy but flat at 1.9 times.

Let me take a second to talk about where we are in the audit and SOX 404 process. Our audit is complete. We've completed that cycle with Deloitte & Touche reviewed those results with our Audit Committee.

On the 404 side, Jeff and I have reviewed the results with Deloitte and our Audit Committee and PNM does not have a material weakness under 404. So we have completed our year-end SOX 404 process as well and we would expect to file the 10K on February 28th.

On slide 15 let me provide you some cash flow highlights. Cash from operations up 3.1%, almost $236 million, free cash flow at $52.5 million, a bit lower than a year ago. The key drivers in that are demand for the winter heating season, as well as higher gas prices, drove accounts receivables up. Those obviously will be collected here in early 2005. We also had our investment in Luna that wasn't in our base plan and we also had about $5 million of cost, capital and O&M, related to the TNP acquisition. And we also raised the dividend, which had an impact on free cash flow in 2004.

On the construction side, our construction program is down about 19.4%, or $33 million. Remember, in '03 we had an enormous plant maintenance schedule. We're back to a more normalized schedule and we also see process improvements on our T&D gas and electric construction programs.

On the liquidity side, we did add a new revolver at our holding company at the PNM Resources level in November. Remember, $100 million of that $400 million will be used to finance the TNP debt component of the transaction once we close. Short-term debt at $94.7 million, down about $31 million, and it just shows that that's where the free cash flow between that and Luna, where that was used.

On slide 16 let me provide some detail on the Cap Ex numbers we provided you in the December earnings guidance release. The core Cap Ex is basically flat for the 5-year period that we showed you last year versus what we provided this year. We saw about a $28 million decline in corporate, which was largely IT spend, as well as our building maintenance costs. The decline here is really driven by some major investments that have now completed in system infrastructure for our human resources area and our financial areas.

Base generation is up about $16 million; that's additional investments for improvements in Palo Verde and San Juan. Gas distribution and transmission is down about $4 million; that's the winding down of our bare main replacement program as well as process enhancements on our construction in the gas delivery business. And on the T&D side, that's up about $22 million. It's largely transmission projects associated with growth, as well as just strong growth in our 5-year forecast for the base utility operations. And again, there's some offset to that. That's the result of process improvement enhancements in the way we do construction in our electric T&D business.

On slide 17 let's review the dividend policy because that was also a change from the last time we talked. If you take a look, our annualized growth in the dividend has been about 8.9%. In December we raised the dividend because of a change in our payout ratio philosophy to 50 to 60% of consolidated earnings. As a result, the dividend was increased 15.6% and we will review dividend policy again once the TNP transaction closes.

Let me turn your attention to slide 18 where I'll reaffirm earnings guidance for 2005 at $1.40 to $1.55. Remember, that doesn't have any affect of the TNP transaction in it. We will revise earnings guidance at the time the transaction closes. The $1.40 to $1.55 provides for some fairly strong growth in our business if you think of the $1.43 that the business achieved this year. At the high end we have a potential for over 8% growth in the core business. For those of you who have been following us, you know these factors very well that will drive us through the range of the $1.40 to $1.55; plant availability always critical, weather, wholesale growth, what does the short term spot market look like on the electric sales side, as well as our ability to continue to maintain costs.

On slide 19 let me confirm our 2005 guidance assumptions. At the low end of our range, we're assuming an average power price of $42 in the market. That's versus $45 that we recognized in 2004. Merchant sales velocity at 1.5; it's been 1.9 the last 2 years. Retail electric load growth at 2% at the low end of the range; it was 3.3% this year, 3.2% last year. And gas customer growth, which has been consistent, at least as long as I've been at PNM, at 2% and we're predicting 2% at the low end of our range again this year.

Now let me turn it back to Jeff for a legislative update.

Thanks, John. We are in the legislative season and so let me just touch on it briefly. We're about halfway through the 60-day session in New Mexico and I think things are moving fine. We don't really hit the fun time until the last 2 weeks when the real press comes forward about getting things through both -- at both the House and the Senate. But there really isn't anything that is deeply concerning to us that I think has got much of a chance of going through and there are a number of bills that we have that we're pushing that I think continue to wind their way through the legislative process. So at this stage, net net, I think the New Mexico session should be neutral to positive for us as we go through its completion.

At the federal stage there's two major issues that we are very focused on. The first one is the Energy Bill and I would have to say that I'm more optimistic this year that we will get something and a major reason for that is a shift in the approach and philosophy of Senator Domenici. I've had the pleasure of meeting with both he and Jeff Bingaman and together, which is unique and very positive, and I think that that will help lead to a much more -- a greater chance of a successful bill passage this year. What's going to happen on the House side is still on the table, but honestly, I do think that we've got a good chance of getting an Energy Bill.

The other one is environmental legislation, particularly Clear Skies. This is a bill that we are in strong support of. We recognize that it may, and this will be decision obviously by Congress, it may be necessary and appropriate to address carbon in some way. I'm frankly pleased and optimistic to see people indicating that a mandatory cap may not be necessary to get it done, but that we may need to address carbon in some way. And so I'm certainly hopeful that we will get a Clear Skies Bill through this year. That level of certainty of environmental regime is an important aspect for all energy players that are in the generation business particularly to have a sense of what obligations they will have going forward and what the economics of it will be and to rely on market forces to lower the cost of installing the appropriate emissions.

So with that, again I want to thank you for your time and attention today. And we will open up the floor for questions.

Ladies and gentlemen, thank you for your participation on today's conference. (OPERATOR INSTRUCTIONS)

Our first question comes from the line Brook Glenn-Mullin of JP Morgan.

Could you just remind us what level of returns you are earning on the transmission business today and what investment you have there?

Isn't it about 75 million, Tom?

And it's earning low mid single-digits.

Mid single-digits.

Yes, mid single-digits, so somewhere between 4 and 5%.

Okay. And how long do you expect the process to take in terms of from filing to actually seeing some sort of relief on the transmission side?

Well, at the FERC, we will end up probably with rates going into effect, subject to refund, and the process can take anywhere from a year to 2 years. It is -- there aren't statutory limits as there are on rate cases in New Mexico, for example, so it really kind of depends on the process with the ALJ and what the potential for settlement may be. But we'd say a year to 2 years. I know that's a fairly wide range, Brooke, but it's a little more flexible, shall we say.

And lastly, can you just give us a sense on the environmental side if the Clear Skies is passed, where do you stand in terms of compliance?

Well, we have -- as you remember, we put in a major investment to upgrade the scrubber systems at San Juan a few years ago and reduced the level of SO2 emissions by about 55 to 60%. But my -- depending on how the Clear Skies is actually implemented and the allocation of allowances, we probably would do some more things on the SO2 side. NOx would be an issue because the vintage of these boilers is such that they are not using low NOx burner technology, but we would not anticipate that we would have to do much more than -- and this isn't insignificant -- but low NOx burner technology and overfire air.

And then on mercury, obviously that's the wild card because the only -- we have co-benefits associated with the scrubbers, but we have no other mercury removal technology installed at the plant.

And I think the key in one of the things about Clear Skies that it does well is it provides a patterning that provides time to make rational investments to get to very aggressive goals. In total, Clear Skies would reduce emissions by about 70% and that's on top of the 40% reduction that we've seen since the 1980 timeframe.

So for us, yes, we would have to make investments. I can't, at this stage, and wouldn't give you a dollar estimate on what it would be, but we also -- I think New Mexico has a strong track record on the recovery of environmental related costs. And so I feel pretty comfortable about the recovery of those costs. But we will end up spending capital.

Thank you. Our next question comes from the line of Robert Petrosino of Barclays Capital.

Can you just provide a little bit more color around the negotiations at New Mexico and the level of opposition there, if any?

Well, I really can't provide much color because until we're ready to announce a result, I wouldn't want to have you leaning one way or another just because not all the facts are out there. But I would say that we are optimistic. We have had good constructive dialog with them since the middle of January. And I'm sorry, I wish I could tell you more other than I think things have gone quite well in the discussions and stay tuned.

Thank you. Our next question comes from the line of David Grumhaus of Copia Capital .

Can you talk a little bit about your timing on closing TNP? And I realize it's somewhat dependent on the settlements and stuff like that, but what you're looking at, you're still looking sort of midyear?

I remain optimistic that we will close in the second quarter. And my -- right now, if I had to wager, I would talk about the middle of the second quarter. I don't think it'll be early in April and neither do I think it'll slip to end of June.

Okay. And financing still left to do, et cetera, can you review that again?

I'll ask John to cover that.

Sure. We have about $300 million to raise to complete the funds necessary for closing the deal, as well as refinancing the securities at the TNP Enterprise level. Remember, we were going to do about 150 million of that in common and 200 or so in mandatory convertible securities. So we will be refining those plans as we go forward and get closer to closing.

And the mandatories you've done half of? Or is the 200 beyond what you've done already?

Yes, it would be above because we needed 250 for the -- or 200 for the transaction with TNP. And then remember, $100 million additional that we announced to finance the Luna plant.

Oh, right. Okay.

And so the likelihood is that we would do that altogether.

Switching gears a little bit, the San Juan plant, obviously you had terrific performance there. Are you confident that you can continue to run that plant near these levels? Any reason to think that we'll see any step-down this year or next year?

Well, you always have changes in maintenance schedules. Part of the thing about San Juan is we have 2 larger units than the -- and 2 smaller units, so when you have a major overhaul on a big unit, it has a bigger impact than when you have a major overhaul on a small unit. But I have -- I've got good faith in our folks that are operating the facility today and some of the changes that they've already put in place from a process side. And as well as the attitude of our folks out there.

We've also recently completed an analysis about life extension at the plant and it's all promising. And that includes a fair amount of work on what the real state of the facility is. And any time you've got plants that have been run as hard as San Juan and they've got 30 years under their belt, they start to sag a little bit, kind of like you and I. But this plant I think has got a good future ahead of it beyond the 40-year life cycle and it's going to operate in a clean way. And I expect to see strong performance this year.

And if we see strong performance out of Palo Verde, which is really where we suffered a bit this year -- or 2004. Palo Verde's performance was not as strong as had been hoped for. They did obviously have some rather unique circumstances that took the units offline. But at the end of the day, it ran at one of the lower capacity factors it has in the last -- in fact, it may be the lowest that it's run at in the last 10, 12 years.

So even with the Palo Verde -- you have a steam generator placement there on unit 1, is that right?

Yes.

So even with that, we still could see a big step-up there?

Well, I think we'll see an improvement, yes. It operated in the low 80% capacity factors this last year and I think we'll see an improvement from that.

Remember the 86% that it ran the year before had a steam generator replacement in it.

Thank you. Our next question comes from the line of John Hanson of Imperium.

A couple of questions here. First one is on the Texas merger settlement. What's the rate base over there in Texas? Can you tell me what the rate base is in Texas versus New Mexico?

On the T&D side, it's about 75 or 80% Texas, 20% New Mexico, roughly split. Off the top of my head, it's about $200, $250 million, somewhere in that range, and about $65, $70, so it's a little more than that, $65, $70 in New Mexico.

Okay. So as we look forward to see what the earnings power of the Texas part of that may mean, we can use the 40% equity multiplied by that kind of number and we can come at the return that you were allowed?

Yes.

To come up with ongoing earnings...

That's on for the T&D for the delivery side.

Right, right. What else do we add to that as we do our numbers?

Well, it's the REP, the retail electric provider, which is called First Choice, is the source of the margin revenue from the sale of the actual commodity to customers. And I'll have John kind of go over the guidance that we've given on for the REP in the past as we've looked at that. Although I really -- at this stage I can't break out the numbers between the delivery business and First Choice. You can, but I'm not going to because TNP has never provided that breakout. I will tell you that once we own the asset, own the company, we will break it out because that's just the way we look at it. But John, you want to give the overall guidance for TNP?

Sure. Remember when we talked about TNP, we talked about it on an EBITDA basis because that's really the way they report. And sort of drew a circle around $140 million of EIBTDA was what we were using to value the business. And I don't think we see a change in that as a result of the Texas settlement. We'll have to see what comes out of New Mexico as we go through the process.

The other thing I would add to earnings power is they are allowed to collect a return on stranded asset recovery, which is about a $90 million asset. And I would point you to their filings because they do some fair disclosure on that. But that is another piece of their earnings power is the ability to collect a rate of return on this stranded asset.

And the $140 million, even with the amortization of the synergy in the first few years, still looks okay to you?

Yes.

Okay. And then ongoing do you have any idea whether there'd be a rate decrease or a rate increase kind of situation after that period?

After the sort of 3-year rate period, I think that would be very hard to put a point on today.

Okay. Thanks. Let me, if I could, just jump over to Luna real quick. Again, the plan there is to put that into New Mexico rate base?

No. The plan is that it would be a merchant facility.

Oh, okay.

It will help support our wholesale sales. That's the basis. It's not needed within New Mexico at that kind of a level.

Okay. So there wouldn't be any rate increase for that so it's going to rely on the merchant market.

Yes, that investment's for the merchant market.

And just to follow-up a little bit on the outage situation. We discussed Palo Verde for '05, any major outages on San Juan?

Two minor outages.

Two minors.

Both planned in the spring and the fall.

San Juan doesn't have another major outage until 2008. Is that right, Hugh?

That's correct.

So we'll have minors in-between.

And that's...

Just to put that in perspective, a major is usually 5 to 6 weeks and a minor, Hugh, is running 2.5, 3 weeks. So it's about half the length of a major.

Thank you. Our next question comes from the line of Gary Low of Delaware Investment.

I wanted to find out for the 140 million EBITDA that you provided for TNP, does that include the load growth kind of net of the rate reduction and savings credit?

Well, it's got all of that in it and I would not -- let me put a caveat without getting fixated around 1 single number. We looked at a whole set of scenarios using what I would call reasonably conservative, particularly at First Choice because First Choice today, given its power supply sourcing, is at a competitive disadvantage.

So we have not made assumptions about relying on significant or even virtually any growth in our modeling analysis just because I think there's uncertainty and we want to wait until we get our hands on it.

Okay. And could you remind me what the current ROE at TNP is because there are public documents out there and there was like a 20% ROE in there.

I think what I mentioned earlier was that they had, based on 2003 data, they've made a public filing that showed it in excess of 22%. And the settlement that we have is effectively based on a 10.25 I believe, 10.25%.

Thank you, sir. Our next question comes from the line of Terran Miller of UBS.

I was wondering if you can give us some indication based on the fact that you averaged about $45 last year and the low end of your range is at $42 assumption, what your view of the wholesale market is, especially in light of what happened for the pronouncement yesterday in California about potential shortages in Southern California.

Yes, I'm going to ask Hugh Smith to handle that and make whatever comments he wants to make about California's announced shortages.

We're seeing prices a little higher than last year. Not significantly higher and that goes along with higher natural gas price forecasts, which has really caused the spark spreads to be squeezed a little bit and not look like an exciting year, but something that's more consistent with what we've seen over the past couple of years. Recall that last year we had a relatively mild summer across the Southwest region as a whole and to the extent that there's normal weather and the fact that demand growth has continued to be strong in California, I think there is a potential for a strong year there this year. I think that the shortage calls sometimes are out of an abundance of caution and sometimes out of conservatism, but we do see a potential with some strong weather out there to have some spikes this summer and could have a strong year out there at this point in time.

Be aware as well that although California's been inundated with a significant amount of precipitation this year that the bulk of the hydropower that serves that area is in the Pacific Northwest and that area is actually below its normal precipitation levels for the year. And so contributing to some of this is the fact they they're not projecting a real strong year from the hydro side as well. So all in all, we expect to see some potential for some strong prices out there. We're not overly concerned that there's going to be anything like what occurred in 2001.

I did hear, Hugh, that they are looking at putting in a low-head hydro on the Los Angeles River in downtown LA.

Now if they could do something with the mud, they'd be much better to produce electricity.

Do you have any idea what the sensitivity is for $1 increase in the megawatt hour prices?

I tell you what, that's getting harder and harder to do because so much of our power is sold long that $1 increase really predominantly affects the churn.

Got it.

But we do say in our guidance assumptions that we think it's about 2 cents of EPS.

Thank you, sir. Our next question comes from the line of Michael Lapides of Hibernia.

Easy question; what was for the quarter the mark-to-market impact on forward wholesale sales?

You had to ask a question I don't know the answer to. And I'm looking around, does anybody have that off the top -- we certainly can get that for you, Michael. I don't know it.

I want to say it was in the $2 million range, Michael, but I don't have the number right here in front of me.

It certainly wasn't large, 1.8 million, something like that?

Yes.

That's perfect. Thank you. Just wanted to check.

Thank you, sir. Our next question comes from the line of Paul Patterson of Glenrock Associates.

Most of my questions have been answered, but I wanted to just touch base on a couple of things you mentioned. One was the San Juan life extension that you were looking at that and I was wondering when's the current life due to expire, I guess? And what's entailed in that is that an accounting review or is that an actual physical review that you guys are thinking of and might that impact new source review or anything?

Let me make a few comments; I'll ask Hugh to add any stuff that I miss or goof up. The review, it's a physical review of the capability of that unit to operate beyond what is a traditionally accepted 40 year life for a coal-fired facility. San Juan was put into service -- I think the small units were put into service in very late 1960s, early 1970. I take that back, it was, I think, if I remember, '71 and '73. Units at 3 and 4 were put into service in '79 and '82, so they range from about 30 years old to about 22 years old. But the life expectancy analysis is really, at this stage, just -- the long range planning, what's the potential of this plant running beyond 40 years, Hugh?

Well, generally when you put these facilities in, a 40 year life is generally accepted life expectancy of these types of facilities. And so at this point in time, you'd typically take a look at your capital spending plan and what you would do at that facility in terms of investment in order to make good decisions as to whether or not you should begin to wind down those capital decisions or begin to make plans to extend that life beyond.

And what we're finding is that it makes good sense for us to continue to put capital into these facilities that the life expectancy goes well beyond the 40 year life into at least the 10 to 15 year period beyond that point in time. And what we'll begin to do at this point, then, is begin to analyze the types of capital that would be required to get the same type of performance out of this facility that you expect from a base load plant over the long term and how that would translate into the capital that we would want to plan on spending over the next 5 to 10 years.

With respect to your question on NSR, we're not really concerned about that from the perspective that to the extent that we do any of these type of revisions and capital investments, any considerations for environmental permitting will be taken into consideration with respect to the type of changes that will be made. And we'll have all the approvals up front in terms of what's necessary to make sure that the environmental agencies are completely onboard with the types of investments that are made going forward.

Okay. Let me ask you this, then, if -- you're saying the 10 to 15 years you think you can extend the life, what does that do to depreciation and when might that depreciation change take place? We found that there have been some companies that have significantly increased their earnings as a result of looking at a longer life for some of their plants, PG&E, and I was wondering if there is some potential upside with respect to EPS from a depreciation perspective.

Typically that would be correct. Basically we have to file with the Commission, though. We've got requirements that we can't change our depreciation rates unless approved by the Commission. We just filed our last 5-year study and so we'd have to take that into consideration in the next study that we would in fact file.

Would that go to rate payers or would that go to -- would that go to the company, the lower level of depreciation?

Depending on the timing, if we were in a rate case, we would reflect those new depreciation rates in that filing. If we were not in one, they would go to the bottom line.

Okay. And since -- I guess I'm wondering, is there any potential -- mightn't we see something happen here and when might we see it?

My suggestion on that one is we don't see anything in the near term. We're not at a stage to -- because we haven't done all of the evaluation about what would be the additional capital requirements, et cetera, and done the life cycle analysis, all we've really done at this stage is determine that it's physically capable of being extended. I would not expect that you would see a change in depreciation rates in the near term, meaning in the next couple of years. I think it's premature at this stage.

Okay, thanks. And the other thing, just in general looks like you guys are a little bit conservative on retail sales growth. You've had a considerable amount -- I'm talking about electric sales growth. I think you mentioned for the last couple of years it's been north of 3% and yet I think your guidance includes 2%, if I read your -- if I heard you guys accurately and if I read the slide accurately and perhaps I didn't. Is there some reason why you think the sales growth has been as slow or if you could just elaborate a little bit on that?

Well, I think 2 things. One, we have -- by nature tend to be a little more conservative. Number 2, you're right that we continue to see stronger growth in our forecast, but really it doesn't have as much impact on us as it may some others because when we have retail load growth, what it does is it moves power away from the wholesale market. And the margins between retail and wholesale are not that different. So because of the mix that we play, I think we also mitigate the volatile swings that you will see because of retail load growth going up or down. And also, the chart that you're referring to that talked about 2%, I think that's the low end range, not necessarily our forecast. Our forecast is a little higher than that. But that's the low end.

Thank you very much, sir. Our next question comes from the line of Ashar Kahn of SAC Capital.

Can I just ask you in your '05 guidance how much are the costs related to the ongoing merger or are those not included?

Those are not included. Remember, it's just at this point a forecast for PNM Resources without TNP, and we won't be updating that until the closing of the TNP transaction.

Neither the costs or the earnings that could come from the TNP transaction are included in that guidance.

Assuming the transaction closes, will you then provide us a new earnings guidance for the year?

That's our intent.

Okay. And second question I had was were you hoping the transaction to close are you looking further? I just wanted to get a long-term strategy of PNM. Are further acquisitions part of your future strategy to increase your footprint?

Well, we are -- yes, we are interested in continuing steady growth that has purpose in both our commodity business, so assets, generation assets, and we'll also look at effective transactions that would expand our T&D footprint. So yes, we will continue to look for what we would consider to be attractive acquisitions on both sides.

And could we see such kind of announcements in the next couple of years?

You could. You may not, but you could. Obviously there's nothing -- I'm not announcing anything and you wouldn't hear from us until we do.

Thank you, sir. Our next question comes from the line of Maury May of Power Insights .

I would like to just ask you if you could summarize. You've made a number of different comments on the weather in 2004, but if you could summarize those comments for both the electric and gas sides of the business, I would be appreciative. And second of all, some comments on the first quarter '05 year to date.

Mild summer, normal winter. That's for the winter up through December 31st, '04. So I think what that meant -- translated, that means we had good gas sales at the end of '04, we did not have the greatest summer on the electric side.

You think of it as quantified, we lost about 7 cents on weather on the electric business because of the milder summer, but then we picked up 3 cents on the gas business year over year because we had a normal winter heating season.

Okay. What about year to date this quarter?

Well, we haven't released anything. We typically will release sales data for each month and I'm not sure when that's scheduled to go out, it should be going out fairly soon. But I think from a weather side so far, it has not been -- the cold that we saw in December has not continued. In fact, I think today it's probably supposed to be 50. So I'd say the gas loads have not been up to a normal range the first part of this year so far.

And then moving to the Luna plant, I believe that when you bought it, you bought your piece, your 190 megawatt piece, you invested $10 million and you estimated the cost of completion would be another 40 million. And is that 40 million that you're reducing today to 30 million for a total cost for 190 megawatts of 40 million? Have I got that correct?

No, my recollection -- and I'm looking at Hugh as I say this and I'll look at it on a total project basis. We said the cost of acquisition was roughly $40 million and we expected the cost to complete to be another 110. So that was 150 million.

Okay, but you own one-third of the plant.

Right. And all I indicated today was that the cost to complete we now expect, instead of being 110, its going to be 100. So it's a $10 million reduction.

Okay, so you're doing it on a total plant basis.

I'm doing it on a total plant basis, yes.

Right. And then my final question, Jeff, has to do with your optimism on federal energy legislation. This is a bill that's been pending for 4 years and I'm just - I'm a little dubious perhaps, but are you looking for an omnibus energy bill passing or are you looking at piecemeal energy bill, say on the transmission rules or whatever?

Well, what I'm really looking at when I say energy bill, I'm focused obviously on the electricity title.

Okay.

Almost had the electricity title go as part of the omnibus budget bill at the end of last session and it was -- it was a leadership call not to pull it out because of other things that it could raise. All I said -- I said I'm more optimistic. That wasn't making a judgment about how optimistic I was in the prior years. I don't mean to split hairs, but it is an uphill battle. There's no doubt about it. But I've got to tell you, Domenici and Bingaman are working hard and their staffs are collaborating. I've spent time with them; we've got some very good interchange going.

Now, even if the Senate gets through, then you got to go to conference and that will not be easy, but it will certainly be farther than we've gotten in the past. So I would say I think there is a reasonable chance. Whether you get an all inclusive energy bill, there's a lot of things that have changed. If you throw ANWAR on the energy bill, I think that's trouble. The ethanol dynamics obviously have changed since the election. But I don't hope to see and I don't necessarily expect, even though piecemeal bills are being introduced left and right, I don't expect to see the electricity title splintered apart and only passed in piecemeal.

Okay, good. Thank you very much, folks.

Thank you, sir. Ladies and gentlemen, at this time there are no further questions. I would like to turn it back to our management team for any closing remarks that they may have.

Well, I would just like to thank you all for your time and attention today. Again, we're very pleased with the year that we had, but we're not satisfied. We're committed to making 2005 even better. So we look forward to our next visit with you. Take care.

Ladies and gentlemen, thank you for your participation in today's conference. This does conclude your presentation and you may now disconnect. Have a wonderful day.