PNM Resources Inc (PNM) 2007 Q4 法說會逐字稿

Good morning and thanks for joining us. In addition to those in the room, as you know we also have a webcast on, so we will try to be careful and point out where we are in the presentation for those people that aren't with us in person today. For those of you that I have not met, I'm Jeff Sterba, the Chairman, President and CEO of PNM Resources. Joining me in today's presentation are Pat Vincent, who is President of our Regulated Utility Operations; John Loyack, who as many of you will remember used to be our CFO, is now back as our CEO of the EnergyCo joint venture with Cascade; and Chuck Eldred, our Executive Vice President and CFO. Also with us are a few members of investor relations, Gina Jacoby, who is the head of it, and with her are Frederick Bermudez and I think [Francine] (inaudible) around here somewhere.

I appreciate you joining us today and we are going to spend a little longer than we typically would in presentation because I think we clearly owe you a complete explanation about the results of 2007. In addition, for the first time we're going to be giving guidance by sector of our business as well as giving two years of guidance for the first time. So with those two giving guidance in that way along with the disappointing 2007 results, we're going to make sure that we give you a complete picture and story. After my overview we will spend a little bit of time on each of the three major market segments or business segments that we have within the operation, and then Chuck will come back and tie it up together.

But before we get started, I want to remind you of the ever-expanding Safe Harbor that gets bigger and in smaller type every time. But please recognize that we will be giving forward-looking discussion throughout the presentation.

Turning to slide five, clearly 2007 was a difficult and challenging year and it was caused by a number of factors that converged on us which we're going to talk about. As a company for that for the 7.5 years from the start of 2000 until -- or through April of 2007 when we generated a total shareholder return in excess of 300% when our peer benchmark only returned about 180%, to have that turn around and for the eight months or so since May of 2007, to have our total shareholder return decline 37% compared to a benchmark of a negative 7% is obviously a sobering and disappointing outcome. We understand the reasons for it. We're going to explain those to you and we'll give you some background about the action steps that we're taking to do it to turn this around.

For a number of reasons, 2008 will really establish a new baseline from which our growth trajectory will occur, and there's a couple of reasons for that. Think about the changes that we're making to the business or are in the process of making today. We're exiting the gas business, we're ending what has been a merchant utility model, a very unique merchant utility model, within PNMR Utility, as well as migrating most of our unregulated operations into the EnergyCo joint venture. So there are a series of fairly significant changes to the structure of the business that are the basis for creating a new baseline of performance.

Now if we look at the fundamentals of the business for reasons we'll talk about, I remain convinced that there is great opportunity within both our regulated and unregulated operations. But the regulated side, particularly within Mexico which has faced its challenges emanating from a five-year global settlement that was put in place in 2002 that, given those changes, we have faced some difficult roads in 2007 and it will take a little bit of time to right that ship. It will not be able to be righted in quick order just through one rate case. It will take a little longer than that.

Let me talk about this in the context of what has happened over the last couple of years. You can see on slide six that, in terms of our earnings per share, we have demonstrated very strong growth, in excess of 11% compounded per year, or just under 11%, between the period of 2002 through 2006. On the right-hand side, you see the fundamental breakouts of that between three major categories -- PNM Electric operation, First Choice Power, and All Other resources. The foundation for a lot of this growth was the global settlement that we entered into in 2002, which was rather unique. Effectively, we exchanged not having a fuel clause for the ability to retain all off-system sales revenues, revenues made from wholesale contracts. And, given that, we aggressively grew the wholesale business and did it very successfully. We extended that growth in 2005 by acquiring TNP Enterprises, which gave us another piece of a regulated operation with a distribution business in Texas and Mexico as well as moved us into the ERCOT competitive markets through First Choice Power, a competitive retailer.

In 2006, we used that platform to expand our physical presence in Texas through the acquisition of the Twin Oaks Coal Plant. At the end of the year, or really in 2007, we then created the joint venture with Cascade because we saw that additional capital was going to be required to grow this business appropriately and we transferred Twin Oaks in 2007 into that joint venture. All of the steps were geared around filling what we knew would be a flattening out of the growth of the wholesale business because a lot of the wholesale business growth was driven by the ability to use the excess generation within our regulated fleet of assets in our unregulated fleet. Recall that the merchant utility model allowed us to co-mingle our regulated and unregulated assets within PNM, the utility, and use all of the surplus energy available for the wholesale market. Effectively, we treated our retail load as just another full requirements wholesale contract.

On the right-hand bars, what you can see is that the major source of decline in earnings from 2006 to 2007 is within PNM Electric. It's $0.36 a share, which is a little more than half of the total decline. We also saw a significant reduction in First Choice Power of about $0.25 a share, and this is on diluted basis. The dilution is included within these numbers, about $0.25 a share. But remember that when we closed 2006, we said that 2006 was a stellar almost perfect year for First Choice Power, and we'll touch on that in a few minutes.

Let me spend just a few minutes talking about what drove these changes within the PNM Electric operation by turning to page 7.

As I mentioned, the merchant utility model allowed us to sell surplus energy out of the jurisdictional area mixed with the resources that we had that were merchant to put together better products to serve into the market. One of the things that happened is that our retail loads have grown much more rapidly than we anticipated and this is shown in the graph in the upper left-hand corner. This compares what our retail sales for the summer, just the three months of the summer, were for each of the years 2002 through 2007 compared to the available baseload generation, which includes purchases, contracted purchases, not market purchases. You can see that while in the early years we had a fair amount of energy available to sell during the summer, that started to cross over, and clearly by 2007 we did not have sufficient energy to sell. We did not have sufficient energy within our regulated assets to serve those loads. What did that mean? It meant that we to go on and either generate off gas or buy purchased power at a cost of $0.065 to $0.08 a kWh, but we were only being compensated by the generation component in our retail rates, which is just under $0.04 a kWh. So that is a position of trying to make it on volume, which obviously doesn't work.

And this was a recognized challenge that we faced, but with reduced performance with Palo Verde and in 2007 with San Juan, as shown on the right-hand upper graph on slide 7, we faced the challenge of having to use more gas generation and more purchased power.

Now also in the lower left-hand corner, you will see that our fuel costs for these baseload resources was increasing. You may remember that the global settlement that we entered into had two rate reductions -- one in 2003 and one in 2005. They were largely funded by going to an underground coal mine at San Juan, and that's this significant reduction in coal costs that you see going from 2002 through 2004. But since then, we have seen coal costs increase at a much higher rate than we anticipated. It has been up about 6% per year. The primary drivers for this have been, in going to an underground cool mine, we are using a lot of steel and gunnite, or cement, to support the internal infrastructure of the mine. I am sure that you have followed what has happened to steel prices and cement prices over the last three or four years, they have increased. Cement is probably up about 50%, steel is up close to over 300%. So the costs -- and then the other major item that we use is gasoline for powering the trucks in the mine. So the costs have gone up much more than we expected.

Added to this was the cost of increased underground mine safety caused by legislation enacted after the West Virginia coal mine disaster. For San Juan, for example, that was more than $10 million a year just in order to comply with that legislation. So we have seen significant cost increases in the coal mine. We are also starting to see increases in Palo Verde costs as the elements of the fuel cycle are starting to move up in Richmond and in fabrication and as we move forward obviously in the uranium itself where you have seen uranium prices move to about 10 times the level that they were two, three years ago. So we're seeing baseload fuel costs move up.

Last component of non-fuel O&M for our baseload generation, we have managed the San Juan O&M fairly well. It has increased, but it has increased at about 4, 4.5%. Palo Verde, however, has been another story, and Pat will talk about this more. But we have seen non-fuel O&M at Palo Verde increase at greater than 17% a year as the people operating Palo Verde have struggled to return it to its premier operating status.

So the combinations of these factors have moved what was a very good global settlement and provided strong growth for the Company for about 3.5 to four years, in 2007 the tables turned. It was using in order to serve our retail loads, we're having to use much more expensive resources for which because we did not have a fuel clause we were not being compensated. And that's the major driver of the $0.36 a share of reduction in the electric utility.

Now as we saw this happening, we expedited our efforts to execute on four key initiatives. The first one obviously is to obtain fair regulatory treatment for our regulated utilities and the major piece of that is our PNM Electric rate case which Pat Vincent will discuss in a few moments. The second has been a need to streamline all of our operations and processes to make sure that we have reduced our costs wherever possible. That was an effort that had been started earlier in the year and in the third quarter of 2007 we gave you a briefing about a major initiative that we had underway that would drive costs out of the business, and Pat will also talk about that.

Let me spend just a few minutes on the next two. The third is the separation of the merchant operations from our utility at PNM, and this is really driven by regulatory simplicity. Having this commingling of assets works fine when you don't have a fuel clause, but if you're going to a fuel clause, it makes it very difficult number one. And number two, it allows frankly for the jurisdiction or retail load to lean on these resources. So what we have done, we announced in January that we have sold off a portion of our portfolio of contracts. That transaction should close within the first quarter of this year. There are four assets that we have unregulated within PNM. It's Palo Verde Unit 3; Luna, the combined cycle facility that we bought, half-built and finished building it out. We own it with Tucson Electric and one of the copper mines, Phelps-Dodge. And then two, peaking generation resources.

Our plan for these resources is as follows. The three gas units will either be sold, [polled] or they will be requested to be included in retail rates. Frankly, this last option makes a lot of sense for our customers, for our retail customers, because these are low-cost assets. Remember, we paid about -- I think we have invested in Luna somewhere around $300,000 a kilowatt. We obviously would not put it into rates at its book cost. It will have to go at market because we're not going to sell the resource into the regulated side unless it is beneficial to our shareholders. But they are lower cost resources that have already been built and are not subject to the continued escalation on equipment and on construction that we see occurring throughout the marketplace. So we think that this may be a good alternative rather than selling or tolling them, but we will have to go through the regulatory process to get that done.

In the meantime, they will continue to be sold into the market place. The last resource is Palo Verde Unit 3, which (technical difficulty) ability we will just toll that resource for a three or five-year period. I believe that nuclear power will continue to move up in value, so we can toll it for a three to five-year period and then look to see what we will do with it at that point in time.

So we are separating the merchant resources that we've had within PNM away from the PNM Electric utility.

The fourth key initiative has been to narrow our focus to our regulated and unregulated electric businesses. First it's divesting of the gas operation. We were very pleased with the terms and conditions, particularly the financial price that is being paid for that asset, and we're also acquiring a small operation in Texas that will get talked about. The balance of the efforts that we will put into the electric business, Pat Vincent is going to discuss what we're doing on the regulated side, John will talk about EnergyCo and I'll add a few more comments about FCP, and also Pat will touch on the environmental sustainability efforts that we have underway. So Pat, let me ask you to come up and address this.

Thank you and, Jeff. For those of you that are on the phone, if you turn to slide 10. I want to reemphasize a couple of things Jeff said. The success in our regulatory business depends on two key things -- regulatory success in New Mexico and Texas and improved operations, especially power plant performance. We are also going to invest wisely in our electric business to meet our growth and environmental goals.

I first want to talk about regulatory treatment on slide 11. A little bit on the New Mexico rate case. The hearings were held last December and we just finished up in January a series of public comment sessions that the PRC held around the state. We were allowed at those sessions to spend about 10 or 15 making comments on the rate case and why we should have the rate increase and the fuel clause, and then the public was invited to comment. We had about 42 speakers show up state-wide, and of those more than three-quarters spoke in favor of the rate agreement or the rate case, both the fuel clause and the base rate increase. Many of them mentioned for example the Standard & Poor's downgrade as a reason that we should have our fuel clause and the need for us to be healthy to help New Mexico. There was a real wide range of folks that showed up. We had environmental groups that showed up, we had retirees, we had shareholders, we had folks from the Chamber of Commerce, folks from The United Way and other low income agencies talking about how important PNM was to the economy of New Mexico. We also had our labor union show up, the IBEW came and the construction and trade union showed up to support the rate case.

The decision from the ALJ is due on February 28 and then the order from the PRC is due on May 7. Our gas case is now in the hands of the New Mexico Supreme Court. Many of you remember, we appealed five issues in that case -- the return on equity, the disallowance of a prepaid pension asset, the disallowance of results-based pay, some cash working capital disallowance and also the way that that quip in rate base was treated. In Texas, we plan on filing a rate case in the third quarter of this year for TNMP.

I want to spend a minute talking about the elements of our rate case in New Mexico on slide 12. We asked for a base rate increase of $77 million, and for the partial year that would be worth $58 million. And all of the assumptions you see here on this slide are at 100% of the rate increase, or basically as we filed. We also asked for a fuel clause in New Mexico and that fuel clause would include coal, nuclear fuel, natural gas, purchased power cost and capacity cost. That fuel clause would be worth $69 million for all of next year if it were in place the whole entire year, and for the partial year it's worth $47 million.

The return on equity that we requested in the case is 10.75%. Now that fuel clause number is a big number, so I want to spend a minute talking about our fuel on slide 13. Our current rates which as Jeff mentioned are effective from 2002 have about $105 million of base fuel in them. The rates that we filed in 2007, and those filed rates in 2007 were based on a test year ending September 30, 2006, and that has $146 million of base fuel in that. That $146 million equates to $18.38 a megawatt hour and the $105 million is about $16.28 a megawatt hour. So in the base rate filing, we reset our fuel.

For 2008, we expect about $157 million in base fuel, and that is based on increased sales. The base fuel rate of $18.38 stays the same, but we expect to have $69 million in fuel costs that would flow through that fuel clause for the entire year. Now that fuel clause is pretty substantial and it's made up primarily of two things. First of all, increased coal costs. We've seen coal costs increase about 25% since the end of that test year. The second is increased loads. What the increased load does for us is it lowers our off-system sales, and when we need to buy, the PPAs are usually based on gas generation and then we also have to increase our own gas generation. So we're basically buying gas at the margin in that fuel.

On slide 14, I want to talk about our second key focus area, and that is power plant availability. At San Juan, we have had top quartile performance for many years and we have benefited from that. We have slipped on that some. We're in the process now of putting in our environmental upgrades. And while we're putting in those environmental upgrades, we're replacing the two leaks in the tubes that caused us the performance issues in EAF. We expect that our EAF is going to go up about 2.6 points, percentage points, this year, and that is primarily due to the work that we completed on Unit 4 in 2007 and the work that's going on on Unit 3 right now that will be completed this spring.

At Four Corners, EAF last year was hurt by Unit 4 and Unit 5 where they had some extended outages on turbine failures. For 2010, they have a major 100-day overhaul on Unit 5. Many of you know that these plants are about 40 years old and this is the first time they've had a major overhaul in some years. So in 2009, we expect a 13 percentage point improvement in EAF at Four Corners based on that outage being completed this year.

At Palo Verde, [Randy Eddington] and his team continue to make progress on the EAF at Palo Verde and the unit performance is increasing. But while that performance increases, as Jeff mentioned, we expect the O&M budgets to go up, and I will talk about how much in a minute. We are also maintaining oversight at Palo Verde. Our new senior vice president of utility operations has a nuclear background, he's a nuclear engineer by training and spent some years at Westinghouse, and that is very helpful to us as we continue our oversight at Palo Verde.

If you turn to slide 15, I will talk about our business improvement initiative that Jeff mentioned. We continue to make progress on that initiative that we announced last year, and in November we had the task of saying good bye to some of our colleagues that had been with us for years and had a 5% workforce reduction. We're on track to be down another 9% of our work force this year. As you can see on the bottom portion of this slide, last year the O&M was $466 million, and that includes $4 million of those ABI savings that we achieved last year. We're on track to achieve $35 million in ABI savings this year. $10 million of that is not in the utility. You will see that there's $25 million in the utility O&M slide, the other $10 million benefits corporate, other, First Choice Power and EnergyCo.

We're hitting those goals. We plan to take out $25 million in costs this year, along with the incremental $4 million that was taken out last year. But we have seen about $20 million in terms of labor, benefits and material escalation this year and about $7 million in other escalation. And that includes things like tree trimming in Texas, some storm reserves in Texas and an increased allowance for bad debt. As our revenues go up, we expect to see more bad debt. But through our business improvement plan, were able to offset all of that escalation in labor and materials and most of the other, so it came out about even. What's happening though is there are some other costs that we cannot control and offset. The first one is Palo Verde and we believe that our share of Palo Verde O&M will go up $13 million from 2007 to 2008. They are making progress on plant performance, but while the NRC has enhanced oversight over them, we believe they're to continue to need O&M increases at Palo Verde.

Another one there is Afton in Four Corners. Afton is in service for the full-year this year, so that is increased Afton cost for that whole year and that outage that I talked about at Four Corners is going to increase our O&M. So next year at the utility, we're looking at $495 million of spending.

If we turn to slide 16, I will talk about our capital plans at the utility. Our capital spending for 2008 and 2009 is forecasted to be $380 million and $373 million, respectively. You can see that spending on existing generation is decreasing. We only have one outage at San Juan in 2009 and much of the spending for the two outages that took place in 2008 took place in 2007 such that we need to buy all the material and equipment ahead of time. PNM Electric spending rises in 2009 fairly significantly and that is attributable to a transmission project called Rio Puerco which will go into Northwest Albuquerque to serve commercial growth that is coming online in that period of time.

We also have about $75 million for generation development in this period of time, and that would be for resources that come online in 2014 and 2015. The new resources that we need in the 2009 and the 2010 period are either done through PCAs, or as Jeff mentioned if we would receive regulatory approval, it could be done with Luna and Lordsburg.

Our ability to spend at these forecasted levels is obviously predicated on rate case outcome that we get in New Mexico.

I also want to spend a minute on our environmental investments. We've spent our money on the environmental upgrades at San Juan and we have experienced significant emissions reductions following the upgrade on Unit 4. The NOX emissions are significantly below our target of 0.3 pounds per Mmbtu, and on the SO2 side, our target was 90% reduction and we're at 95. So that's freeing up some allowances that we can sell on the open market from San Juan. And on opacity, our target was 20% and we're running at about 10%. So very successful environmental upgrades on San Juan.

We're also looking at energy efficiency. Many of you know that Governor Richardson is now back in New Mexico and one of his key focuses for this year is energy efficiency and that is very good for PNM. There is a bill in the Legislature that has been passed through the committees and it should be passed out in the Legislature for the Governor's signature in the next two weeks. It's called the Efficient Use of Energy Act, and it will require PNM to have energy savings targets of 5% by 2014 and 10% by 2010, and that needs to be met through energy efficiency. But there is language in the bill that is very helpful to the utilities. Specifically, it requires the PRC to remove any disincentives to utilities for investing in energy efficiency and it provides that the PRC allow us to earn a profit on resources acquired through energy efficiency programs that it's financially more attractive than those afforded supply-side resources and it also enables us to collect cost and incentives through either tariff rider or in base rates. So the language in that bill is very favorable to utilities looking at energy efficiency.

The third part of our environmental sustainability is solar. We're doing a solar feasibility study to cite a trough in New Mexico. We're working with El Paso Electric, Tri-State and Excel, and this could be brought online either through a PPA or a build, whichever gets preferred regulatory treatment.

We also have a biomass plant in our resource plan to help us meet our renewable portfolio standards, and that will come in at 32 MW and that will come in late 2009 as a purchased power agreement.

The final piece of environmental sustainability is climate change leadership. PNM is very active both nationally and at the state on climate change leadership and we are doing that so that PNMR is not disadvantaged when it comes to climate change legislation so that we can have acceptable things for our customers while still doing the right thing for the environment. We're focusing on three areas of climate change legislation. The first is advocating for adequate free allowances for utilities in the electric sector. We're also looking at price limits on those allowances and then making sure there's sufficient time to reduce emissions so it can reduce the impact on our customers.

As you can see, we have a lot ahead of us in this year, but our focus is on those two key areas -- the regulatory treatment in New Mexico and improving our power plant performance. With that, I want to turn it over to John Loyack, the CEO of EnergyCo, to talk about EnergyCo.

Thanks, Pat. Just to keep everybody on track, I am going to move to slide 19 to start the presentation and talk a little bit about EnergyCo. I think we have a pretty exciting opportunity here to create something special with EnergyCo. 2007 was really a year of formation and progress and foundation building. So we'll go through some of the highlights of 2007. Obviously we were able to establish the structure and start to build out the management team and we'll continue that process in 2008.

From a strategic growth perspective, the contribution of Twin Oaks, the addition of the cogen facility were two big steps forward. And then, we also started a project with NRG on Cedar Bayou 4, a combined cycle low heat rate gas plant that will come online in 2009, in the summer of 2009. We see this as a really good addition to the portfolio. A lot of equipment was purchased ahead of the curve so it has missed some of this price increase that you have been I'm sure following relative to gas equipment and demand for gas equipment. So we think it will be very well positioned as it comes on.

Our model at EnergyCo are to be really active asset managers and that asset optimization and the infrastructure to be able to do that got underway in 2007 including some system work to be able to manage changes going on in ERCOT. For those of you who are not as familiar with ERCOT, today there is a handful of pricing zones. The market is referred to as zonal. It's moving to nodal, where there will literally be hundreds of pricing points to be managed. And we're building software and teams to be able to manage that in the marketplace. That system development work started in 2007.

Then there was a lot of integration work around the assets that were contributed and some very good operational performance. Twin Oaks had EAF of near 90%, greater availability out to our Cogen. And then, we had a successful upgrade to the next level of environmental compliance for our Twin Oaks facility we were able to do that with some low-cost technology that probably cost us about 20 to 25% of the more traditional installations and we think it has really positioned the plant for 2008 and beyond.

On slide 20, if we look at key areas of focus, and now you can think of the transition of EnergyCo to finishing up some formation but really moving to value creation in 2008 and beyond. So we really have four key initiatives. We need to continue to build out our infrastructure. We still need some people in process and we will to working to finish our nodal system. The other thing the nodal system does is it allows us to be a Level 4 scheduling entity in ERCOT. That will allow us to provide additional products and services to our customers as well as optimize the management of our own assets in ERCOT so it will be a big step forward. We will be working with NRG very closely to make sure the Cedar Bayou construction stays on time and on budget, and again available for the summer of 2009. We will be very focused on looking at other asset opportunities, both development, and we're going to talk about Twin Oaks expansion as we move forward here as well as M&A acquisition opportunities and building out the team to do that, and we're well underway with that process. And then finally, maximizing what we have to get the most value out of it. If this is about value creation, we need to get the most out of the assets we have deployed and new assets as we bring it in. And then, we're also expanding our marketing and trading operation outside of ERCOT into the Southwest and West. So those will be key initiatives that we'll keep you posted on as we move through 2008 and we get into value creation mode.

On slide 21, in the 75 days or so since I've been here, we've really been focusing on filling out the strategy for EnergyCo. And I think there is a physical component to that and there is a business model component to that, and I'll walk you through both. On the physical side, we're focused on ERCOT first. We have assets there, we have seen the value of the interplay of those assets. We see ERCOT as a market with shrinking reserve margin and better pricing moving forward, so we see it as a key place to invest. And then right behind that with our expertise, the Southwest and the West would fit that same profile. So that is really the footprint that we're going to go after to build a base for this business and grow it.

When you think of what [mix of] assets, obviously we're off to a good start with a slice of gas and a slice of lignite in the portfolio and we will continue to want to make sure that we have a good fuel mix and that it's low heat rate so that that asset is going to perform over the long-term well and provide returns over the as well. As we also look at the portfolio, we will look at renewables I think from our active asset model. We'll be a little bit more focused on baseload renewables, biomass, geothermal, those types of assets because they will fit our model the best. And if we think about the business model, literally from fuel procurement through the optimization of plant performance to the generation of electricity and turning that into products and services we sell to the marketplace and the customer position itself, we're really trying to tie all of those together and then optimize them within the financial markets as we optimize each of those positions along the way. And we really get the full value out of the entire unregulated value chain in the markets that we intend to serve. That is why we're so focused on systems, processes and people, to be able to ensure that we can do this and do it ineffectively and add the incremental value that we think it will add as we move forward.

Then on slide 22, how will we measure our performance or our value creation? Obviously, 2007 was a startup year, $10 million of EBITDA. We'll see that grow to 60 to $70 million of EBITDA in 2008 as we get a full year out of the assets we have in the marketplace. We continue our active asset management model and we drive value with it. And then, as we move to 2009, we will see that go to 100 to $110 million of EBITDA as we get a half-year of value out of Cedar Bayou and we continue our optimization efforts.

There are some things you should think of in context to those numbers. Those numbers do not include any new developed assets or any new potential acquisitions that we might bring in. That would be additional value creation as we move along. From a development perspective, we do have dollars in our '08 and '09 plan to develop a 600 MW coal facility at the Twin Oaks site. We can certainly talk more about that in q-and-a, but that's in the development budget for those years.

We will continue to fund an M&A budget as we look for good asset opportunities in ERCOT, the Southwest and West. So that's in there and it will always be in there. But the cost associated with the initial work on the nodal system is in there for 2008, but then that will go way as the system finishes up and it won't be in the 2009 and beyond numbers.

And then finally, we still have some human capital in process to put in place in the business. We will finish that in '08, we'll be at a steady-state as we move into '09 and beyond.

So again, I think some pretty exciting opportunity to position EnergyCo well as a value creation entity, to grow it in the markets that we think we can really drive value and see it as a pretty special opportunity. So with that, I will hand it over to Jeff to talk about First Choice.

We left Jeff Weiser in Dallas to run the business, so just imagine I'm Jeff Weiser, you have to put a little hair on my head to make that work. Let me just touch on a few things about FCP.

When we acquired First Choice Power, what we found is a business that was rapidly losing customers, had little or no infrastructure for growth and had a fairly poor power procurement strategy. Thankfully, we did not pay too much for that business. We brought in a talented management team and they have really turned this around. They're building a platform for growth and they are generating reasonable margins in the interim.

If you look at page 24, there's four graphs that let me talk briefly about. First, in the upper left-hand graph, you'll notice that between -- in 2006, we grew our customer count (technical difficulty) at a little over 15%, which is pretty healthy in that marketplace. Between 2006 and 2007, however, that growth was stunted and there's really two reasons for that. The first is that we went through what is always a difficult transition in a customer care system. They really did not have one, and we needed to build one. And so as we built it, we shut down our marketing efforts because unless you have a system and a platform to use, it does not make a lot of sense to try to add a whole bunch of new customers.

We have now gotten through that process and they're moving back into the marketing stage and beginning to reattract a number of new customers. So we added a few in 2007, but it was relatively small expansion. As we look into 2007, we believe we will return to the 12 to 15% customer growth rate and the rate of attraction so far at end of December and into January are demonstrating the clear capability of doing that.

If we look in the upper right-hand box of retail margins, as I said earlier, 2006 was a stellar year. We had high margins and this was true because of a lot of things that happened within that market. It was the last year of price to beat. We had high natural gas prices, we had the [gafuffle] around TXU and the legislative session and so we saw very high margins. In 2007 they returned to more near normal levels. We expect that as we move into '08, they will stay in something similar in the low 20s -- is the probable range that we expect to see on the retail side.

The impact on EBITDA can be seen in the lower left hand corner. In 2006 as I said, we had just as good a year as one could have, partially driven by the high average retail margins, but also driven by trading gains that we made from the small trading operation in that business. You can see in the first two years of operation, we had about $15 million of gains. In 2007, it reversed to a slight loss. This loss was largely generated by the summer of 2007 being wet and cool, which drove natural gas prices down and adverse the positions that we had taken in natural gas.

So as we go from 2007 to 2008, you'll notice that we're forecasting roughly the same level of EBITDA. And you may go, wait a minute, you have 15% or 12% increase in customers, how can that be? A couple of things. First, in 2007, because of the challenges of bringing in the customer care system, the vendor for that system ended up having to pay us about $7 million to help offset those costs that we incurred in the transition as well as the inability to attract new customers because they missed their benchmark performance dates. So that's $7 million that helped compensate for customers we did not get in 2007, but we're starting 2008 at a lower level than we otherwise would have. So the growth that we see in '08 is really making up for that.

The second thing is that we will spend about five times the amount in '08 on marketing in order to restart that marketing effort, which will take it up to around $10 million.

Now in terms of the key focus areas for this business, obviously the key is to profitably grow the customer base. The major components of this are to be able to leverage the platform which we now have developed. It's both from the web side and the web portal we use for customer traction, as well as a multichannel marketing outfit that really relies on affinity and co-branding as its key elements. I'm not going to go into a lot of details on the marketing strategy for obvious reasons, but we've given you more information than we have given in the past in terms of margins, customer growth and what we anticipate in this business.

One of the key pieces for our strategy has been that First Choice Power is a wholesale-led retailer. It is not just a retailer, and there is a significant difference when you look at the way different entities operate within Texas. What it means for us is in a rising price market, we have found that we get out of customer traction much more rapidly than many of the other players. And in a falling price market, we move back into that market more aggressively than we have found other players to do so. This has definitely added in our wholesale optimization where we believe we can keep our margins in the low 20s.

The last point I want to touch on is that we continue to evaluate the potential contribution of First Choice Power at EnergyCo. We're sensitive to the issue of earnings dilution, but we also have to recognize, are there ways to increase the value for our shareholders by doing something different with this business. And I think there are three reasons why we are considering the potential transfer. The first is that we will create a situation in which all of our unregulated operations are within one entity under one management and one set of structures, and our regulated operations will be wholly-owned and under a different set of management.

The second piece is that today we have small trading operations in FCP as well as EnergyCo. There are economies of scale of the consolidation of those trading operations into one and the common management of that operation. The third reason is that the sale or the contribution of FCP and EnergyCo would enable us to monetize the value of FCP, to take that value for the half piece that Cascade would effectively be buying, convert that into capital which will fuel the growth of EnergyCo, which has to be matched by additional dollars from Cascade to invest in the business lines that John talked about. Obviously, the decision on whether or not it gets contributed is a function of what's that value at which we monetize, and other terms and conditions that could affect how earnings are distributed out of the business. So we will keep you advised as to what outcome we come up with, but we are continuing to look at that.

With that, I'm going turn it over to Chuck to tie this all together financially.

Thank you, Jeff, and good morning. Let me start out by clearly indicating that it's obvious that 2007 was an unacceptable year for our shareholders and we certainly understand that the performance of the business and the challenges the Company faces over the next year or two years, certainly we feel that with the message you've heard today as an intense focus that we have to do everything we can within our power to turn this business back to show profitable returns for shareholders.

Let me start by talking about 2007 to bring some clarity around what happened, and also provide some outlook for 2008 and 2009.

To begin with, on page 27, as we've communicated throughout the year, we've talked about some of the challenges we had financially. We reaffirmed the guidance beginning in November to $1.30 to $1.40. The plants at that time were operating okay. We were confident that for the last quarter, the plants would continue to hold their performance but not until November and December did we really start seeing some problems became very evident. Let me give you some examples that point that out.

San Juan Unit 4 was supposed to be back on schedule November 1. It extended through the rest of the year with startup issues. We had forced outages at Units 1 and 2 at San Juan due to tube leaks. Palo Verde Unit 3 startup was delayed until mid-December and did not come back on until January of '08. We issued the 8-K in December to give you some indication that the plants were not performing, and as a result of that unfortunately our results ended up at $1.08.

Now let's look at a walk across from 2007, turning to slide 28. I'm showing you this by segment so you can begin to see a perspective that we have relative to each of the businesses and as we report each of the business segments. Also I think this will provide greater transparency to you going forward and as we begin to report by segments for guidance for '08 and '09, that should also provide some clarity as to how we see the business and its performance.

Let's start with the PNM Electric at $0.28 down before the impact of dilution. Again, the same theme, plant availability, particularly in the fourth quarter, accounts for about 40%. Higher coal costs, Jeff talked about the minor safety act and the rising costs of commodities. The increased plant O&M at Palo Verde, less wholesale sales due to load growth -- all of these had impact significantly to the electric business.

Let me point out again that these issues can be fixed and these issues are being addressed as we speak. We are very intensely focused on turning this business back around.

Let me talk about Twin Oaks, which is the Altura segment on here, at down $0.22. Simply keep that in mind, that in 2006 we had that plan for eight months and we had it during the summer months which was the higher performing months. In 2007, we moved it over to EnergyCo, we had it for five months. And as a result, if you go year-over-year, that's the impact of the $0.22. But also keep in mind, we reported that it was $0.05 diluted when we moved it over to EnergyCo. So look at that as just 2007. And when you run the -- calculate the numbers and you look at moving the plant over, obviously we gave up 50% of the earnings but we made that up through the cash proceeds that were extracted from EnergyCo to pay down debt. That end resulted in about a $0.05 dilution for 2007.

On First Choice, Jeff talked about 2006 being a banner year, and we had the benefit of the price to beat customers and higher margins and higher customer growth. And we also mentioned that some of the trading losses that we had in '07 and large gains in '06 resulted in the impact of $0.20 in that business. Dilution at $0.17 that reflects the issuance of the equity that we had in December of 2006.

So let's shift gears and look at 2008 for guidance. Again, beginning to show you by segment so you can see on page 29. The challenges we had certainly will be reflected as our focus in 2008. On slide 29, you can see the improvements. To add transparency, we're going to be showing guidance for two years, guidance by business segment, to give you a perspective we have for each of the businesses. And we will report those segments throughout the year. Our biggest challenge continues to remain with PNM Electric business.

On slide 30, you can see the guidance of 2007 we earned $0.45 and we're showing with an assumption of full rate relief and fuel clause of $0.45 to $0.60 and we indicated again the drivers of that particular business.

Let me walk through some of the drivers of that business, but you can clearly see from this slide with the performance in 2008 it's largely going to be dependant upon the success of the rate order from the rate case. That becomes a critical aspect of this business segment as we go forward.

On slide 31 let's talk about the favorable variances, obviously the electric rate base. As Pat talked about, for partial year it's $0.42, the fuel clause at $0.34. And certainly the outcome of this rate case, each of you may have different perspectives as to the results of that decision which we will hear a recommendation on February 28 from the hearing examiner. So that will have a significant impact relative to the momentum we have in that business.

Plant availability, we'll begin to see some results in 2008. We pick up $0.09 to $0.15. That is a result of the overhauls that we will see for San Juan units 1 and 3 that will reduce the outages. We'll also continue to focus on Palo Verde and see some continued improvement in the plant. The business initiatives that Pat referred to we see as a pickup of $0.12. But also Pat mentioned that that only offsets some of the expected O&M increases. Palo Verde increases to $0.10 as an impact to O&M. I know that APS reported in their guidance information that they expect the impact of Palo Verde to be relatively flat. Unfortunately, we have not seen that experience in years past and so we're adding contingency here to allow for some additional O&M increases.

The Four Corners outage will also be an impact. We've talked about that, the full year of Afton and normal escalation, all of which will hit O&M increases. Higher fuel and purchase costs, coal cost, up 9%. We talked about that and why we continue to see that as a significant impact. More gas generation from the add-on of Afton plant, which will bring about higher purchased power cost as well.

Again, let me just point out the critical nature of the fuel clause. It's obvious from the calculations and the information we're showing you the fuel clause becomes very critical to the business in order for us to absorb the cost impacts and maintain the financial health of the utility. Other factors we saw in 2008, the SO2 allowances. Really, we used those to help offset some of the fuel when we took on the fuel risk itself without a fuel clause. In 2008 with the fuel clause itself, if we are successful in the rate order, those will be shared with the rate payers. Also, the rebalancing of the trust. Each year, we do a rebalancing of the Palo Verde trust funds. This last year, we changed the equity allocation from 70% to 60% and realized some gains in that.

Dilution, if you recall the public equity units, you will have dilution in 2008. In 2008, that will add about 9 million shares, and then also the private equity units will add 4 million shares in November of this year.

Other impacts include depreciation returning to normal weather and higher interest costs. You can see that the regulatory environment for this business segment continues to be the significant impact.

Turning to slide 32, let me talk a little bit about guidance. On a consolidated basis, we'd see $0.80 to $1.10. They won't add up because when you add them up, these segments become fairly wide and so we narrow the guidance. We've picked up a little bit in the lower end and dropped a little bit in the higher end to show you how we would typically report guidance in this particular year. Keep in mind that we're trying to show you more transparency by showing you the business segments and we'll report that throughout the year. As we discussed, the electric business at $0.45 to $0.60 continues to be really focused on the result of the rate order, which we'll hear something -- recommendation on May 7th. We'll also need to come back to you after the [rendering] of that order to give you an adjustment to guidance to reflect the outcome of that recommendation.

At TNMP, at $0.18 to $0.21, it's down because the CTC charge revenues are down from an adjustment to cost of capital. That's about a $3 million reduction, and we've added some additional O&M increases driven by tree trimming and other factors in Texas. That is the reason why we will be filing for a rate increase in the third quarter of 2008. The PNM Gas for accounting purposes given that we sold the business is treated as a discontinued operation, but as we go forward we'll continue throughout 2008 to report that in ongoing earnings.

We see this segment $0.20 to $0.24. Keep in mind, that's a full year with the rate increase. And in 2007, we did benefit from colder weather in the winter time, January.

First Choice, as Jeff pointed out, we have a wider range because of the trading activities. We typically look at 10 to 15% EBITDA that would reflect the trading of that particular business. As John pointed out, we're moving the infrastructure and the trading function over to EnergyCo and we don't see First Choice really doing any proprietary trading going forward after that infrastructure is in place and EnergyCo begins to trade relative to the unregulated business and the assets we have in that particular business segment.

Corporate and other really just represent the holding company interest expense, about $400 million of short-term debt.

Let me point out too on EnergyCo is as we have talked about and Jeff pointed out in his discussion, we see that as a long-term strategy for the business. We'll report on EBITDA, but we won't report non-cash items because we really see that business to be reflective of its value of cash and its contribution to the business. As we go forward, we will provide that adjustment to that EBITDA, how it affects PNM Resources to contribute an earnings per share, but again I want to point out, the emphasis is really the cash value of that business as we make investments and we build it for the long-term value for our shareholders.

Turning to 2009 guidance, again, we've never reported this, but we really want to begin to show you that we are seeing improvements in the business, we are beginning to see the value that will be focused the efforts in 2008 we will begin to provide results in 2009. Once again, looking at the guidance we would see around $1.20 to $1.50. That does include the full rate relief, both to the fuel clause and the electric business for PNM Electric. In addition to that, with TNMP at $0.22 to $0.24, up from $0.18 to $[0.216], it really reflects the partial year of the rate increase, about $4.5 million or $9 million annualized. The gas if you recall is gone at that point in 2009 and will be replaced by Caprock, and we see a range of $0.05 to $0.08. First Choice, a tighter range as a result of not having the trading function of $0.35 to $0.40. That's up from $0.25 to $0.38 and that continues to [support] the margins of $20 to $25 and growth of customers between 12 to 15%.

At EnergyCo it's a range that we see from $0.01 to $0.07. Obviously we're beginning to see upside potential for EnergyCo. This does not add any additional growth or acquisitions of EnergyCo, but it begins to represent the fact that the business platform, the infrastructure's in place. As we trade around the assets and we see the Cedar Bayou coming online in summer of 2009, we begin to see the contribution of benefits of EnergyCo to PNM Resources. Keep in mind, this is a full year of dilution associated with the conversion of the equity units, which I mentioned was about 13 million shares.

Turning to slide 34, let's talk about the financing of the growth and we put the cash flows both for 2008 and 2009 because of the sale of the gas business. But you can see to the bottom line that there are $300 million, is available for reducing debt as well as for other corporate purposes. As you know, S&P took action earlier this year to downgrade the utility. They dropped the holding company one notch and dropped the utility one notch and placed us on stable outlook. Moody's on the other hand has placed us on a review for downgrade, has not taken action. I can tell you, both of the rating agencies are focusing on the results of the rate case order for 2008. And at that point, we will see what kind of comments or actions they are wanting to take. But as you see from the cash flow that we have, that we have cash as a result of the sale of the gas business and we continue to grow the business with the acquisition of Caprock. If you even adjust the inflows, and this is the middle range of the guidance when we look at the inflows here at $610 million, you would only drop about $150 million of the net difference instead of $300 million.

Now with that, I would like to turn it back over to Jeff for his closing remarks.

Over the last eight years since I came back to this Company, I have been able to stand before you all and talk about the very strong growth that we generated in this business. Total shareholder returns (technical difficulty). It's unacceptable, as Chuck said, and we're committed to turning it around. We hope we have explained what the seeds of this were and effectively that our global settlement lasted one year too long. So we're behind a bit of an eight ball and it's going to make 2008 a challenge. But in no way does it alter or deter my belief in the value of the business and our ability to resurrect that value proposition that we have executed on quite effectively I think for most of the last eight years.

Now I started off early in the conversation indicating that we were effectively going to have 2008 as a new baseline from which we would then grow. And I said that the reason for that is that we are fundamentally changing the business. We are eliminating the gas operation, we are exiting the merchant utility model that we used within PNM and we are narrowing our focus just to the gas business and we are collapsing or collecting our unregulated operations within what we believe will be a stronger growth vehicle, the EnergyCo joint venture with Cascade. What it will do is put us in a position of being able to look at two more clean, clearly delineated businesses.

By the end of 2008, we will have about $2.4 billion invested in rate based and regulated operations. Of that $2.4 billion, most of it is within PNM Electric, but a growing percentage is in Texas. If we look at the earnings power of that operation, the regulated operations would have an earnings power in the $1.60-ish range, whether it's $1.60 $1.65. This shows $1.67 on page 36, but it's in that range. That is substantively higher than the guidance that we have provided for '09, at the high end of the range that we've provided for '09. The reason is that, one, we're going to be a bit conservative. This delineates the challenge that Pat and the folks that work on the regulated site of the business have before them, to get this kind of earnings power turned into reality as rapidly as possible. Will it happen in 2008? No. Will it happen in 2009? Well, I would say, that's still a bit of a challenge. But the earnings power of getting there through a couple of steps is there. It's accentuated by what Pat talked about on energy efficiency. The legislation that will clearly pass and be signed by the governor which gives us the ability to not only earn on energy efficiency, but be financially compensated in a manner greater than we would be if we built power plants is something that will build over time. Will it affect '08? No. But does it enhance the value proposition of the business? Absolutely.

In terms of our unregulated operations, we think that the EnergyCo model will be a very valuable model for building value. As Chuck mentioned, some of that value does not necessarily translate into earnings per share. That's why that kind of a business is largely looked at on an EBITDA basis. Purchase accounting messes a lot of things up in trying to figure out what flows through earnings versus what happens on the cash side. We happen to believe in cash.

Now as we go through 2008, there are things that you can look for to see how are we executing on them. On page 37, there is a checklist of the major challenges that we face for 2008. First is the closing of our transactions to sell the gas business and acquire the Caprock business, along with the continued discipline growth of our First Choice Power operation, which we -- I firmly believe we will see at least 12% growth in customers.

We're going to continue to opportunistically expand our joint venture primarily, focused in ERCOT, but secondarily focused in the West. One of the items that has been on this slide for the last year, last two years, has been the next one, to ensure Palo Verde's return to premier operating status. We believe it's going to take 18 to 24 months, probably more like 24 months. And that plant is going to have to prove itself through operations before the regulators are going to put it back in the kind of position that it will ultimately be. Regulatory approvals will lag operational and performance approvals and we're going to be conservative and believe that it's going to cost more than our operator is saying it will cost in order to return it to that stage.

We completed a major environmental upgrade on San Juan 4. As Pat mentioned, we have two more units going through the same process. These are very complex processes with significant construction and complete new operating systems, digital operating systems, and it's going to be very important for those to come on as scheduled and operate well. While we know how we're going to get the $35 million of O&M savings, not all of the actions that need to be taken have yet been executed. So we will continue to report on our success there.

Last, we will obviously look at the rate case decision that comes out in May and determine what's the next step to help ensure that that utility is returned to financial health and is allowed to earn the appropriate rate of return.

So thank you again for your time. I know we took longer than we typically did, but we really wanted to provide you adequate information. We would be happy at this stage to answer any questions that you have. [Paula]? Because of the people on the web cast, we need you to hold the mic.

Two questions. The first relates to -- will you file another rate case immediately following your May decision? And how early do you think you would be able to go back in? The second question is, I guess I don't understand that you're showing about $100 million two -year improvement in EBITDA at EnergyCo, but the EPS is flat in '09 versus '07. So I'm just not sure what's eating up the improvement in EBITDA on an EPS basis.

On your first question, the decision about whether we file or when we file a second rate case is really dependent on what the outcome is. So it's going to be shaped by what they do in that rate case. But obviously, we're going to be looking very closely at the need for additional rate relief. On the second question, Chuck?

(inaudible - microphone inaccessible) when you actually run the numbers back through PNM Resources and adjust for purchase accounting and the amortization of contracts, (inaudible - microphone inaccessible) EBITDA (inaudible - microphone inaccessible) EnergyCo's reported on a cash basis and we have to run sort of 50% of our (inaudible) based on the basis that we have on the 50% ownership of that particular company. So the adjusted amortization of the purchase accounting for the contracts, take away the interest cost and you'll work your way back down to about a $0.07 calculation on the high end for 2009 and then roughly about $0.02 on the high end for 2008 EBITDA calculation. So we can go over that with you and explain it a little bit clearer, but it's really in purchase accounting in how we have to treat that.

(inaudible - microphone inaccessible) going down by about $20 million?

That's about right, yes (inaudible - microphone inaccessible).

After this, we will see if there are any questions on the Web.

Just to follow-up on Paula's question. Assuming that you guys got 100%, which is what is in guidance, when do you guys you think you have to go in another rate case? That is number one. Number two, in terms of purchase accounting, what was the impact of purchase accounting in your expectations for 2009? And also trading margin expectations for '08 and '09, what are we expecting that in terms of contribution? And also the [PD] trust benefit in 2009, what should we be thinking about that?

On the rate case, obviously we have to wait to see what the outcome is. We will still not be covering our allowed return because of cost increases. So you can expect that we will be filing a second rate case. I'm not going to a date as to when that will be filed, but clearly an additional mechanism is going to be necessary. Chuck?

Again, we may have to sit down and go over some of the details and calculations, but the purchase accounting amortization in 2009 was down about $21 million. Depreciation and other amortization down about $36 million. Then, you have interest expense, so roughly around $30 million. So that gets you to a GAAP on return of income about -- again, using that range of 100 to $110 million, around the low single digits of $24 million. Then we adjust that back to our 50% share which gets us to that range of (inaudible - microphone inaccessible). So again, it's what you add back for purchase accounting, the interest expense and other amortization. And we will provide as we go forward and we report the segment for EnergyCo as we report EBITDA, we'll have a schedule that will take you through the calculations of exactly what they report on an EBITDA from a cash basis and then add back the accounting impacts to that to get down to the net income EPS number. I think that's the best way [to think of it].

On the trading side, your question about what do we anticipate on trading margins, relative to FCP in 2009 we expect no trading margins. We have reflected it on this side, but we really believe that by 2009 all of the trading will be occurring within the EnergyCo side. John, you want to make a comment about what you expect there?

Sure. If you look at the EBITDA range, it's about 10% in '08 and '09 that we would expect to get from the trading operation -- EnergyCo EBITDA.

That isn't such a large number in 2008.

That's right. So if we are at 60 to 70 at 6 to $7 million, if we're 100 to 110, it's 10 to $11 million as you move to 2009.

(inaudible - microphone inaccessible).

Yes that's right.

(inaudible - microphone inaccessible)

I'm sorry -- the question on (inaudible)?

(inaudible - microphone inaccessible)

We rebalance it every year, and generally I'll just say in the past performance, it's usually $0.03 or so. But again, it depends on what the (inaudible) looks like for this year, but we generally get around $0.03.

Frederick, do we have a question from the Web? Let's go to that.

Sam Brothwell, Wachovia.

Jeff, all things being equal, if your New Mexico jurisdiction were to grant you a fuel clause and let's say for the sake of argument the staff recommendation on the general rate case, how would that impact your '09 guidance? Would it still the north of $1.00?

You can run that calculation, Sam, because we have told you what the elements would be or how much is included in both '08 and '09 for fuel clause relief and base rate relief. The only thing that would change that is whether we could file a rate case, a follow-on rate case, that would still result in additional revenues that would be generated in '09. And that is getting fairly tight. If we filed a rate case at the end of August under a 12 -- if it's only suspended for 12 months, then we would have another five months of that rate case. But in reality in this case for example, we have had a 15-month suspension. So we would obviously update guidance as we will once we see the ultimate outcome of the rate case in May.

If you look at the plus and minus items, and I forget what slide it was on, a large portion of the negative drivers that you illustrate for the electric utility would be captured in the fuel clause. Is that not correct?

A number of them would be, yes. Not all of them, but a number of them would be.

Okay, thanks a lot.

Jeff, what is your outlook for EnergyCo's asset acquisition markets. Are you seeing assets that are fairly reasonable for purchase, or are you basically saying the price of assets are too high right now?

We're seeing a market that is a little hesitant because an awful lot of that, as you all know a lot of the private equity that was interested in these assets has pulled back because of the debt market roil. So in one sense there's not nearly as much appetite in the marketplace, but people, because of what they received for other assets, they may have pulled back the sale. I do believe that we will start to see some assets come onto the market, like we're seeing that today, and prices are still high. However, the real challenge is -- what can you do with that asset? If you remember, one of the things we have always talked about and believe in is the building of systems rather than individual assets. Because when you build systems, you can do things that you can't by just owning a single asset in a marketplace that you're either for having to toll or hedge or what have you. So I think you will see hopefully that some of those things will occur in ERCOT that will allow us to enhance that portfolio. So you has the market dramatically dropped in price for assets? No, it hasn't. Has it come down a little bit? Yes. But it's really going to be a focus on what is the asset, what is it located, and how does it fit within our portfolio. John, you want to add anything?

(inaudible - microphone inaccessible) as you think of that active asset management model, the interplay of assets within a market is critical to that and how we're going to create value, and that will be a big driver in our asset acquisition strategy and decision-making.

Do we have another question from the Web?

Gene Pisasale, [PNC] Bank.

Just as recently as November, you guided to improving or at least some intermediate term improving in operating rates on your plants. And the fourth quarter really substantially underperformed that. You're now projecting that Four Corners EAF will be lower in '08. I am concerned about the projected improvement in San Juan and Palo Verde since the recent projections were well above what you delivered. It's just getting a bit frustrating with the projections that we've been getting and what has been delivered and I'm just wondering how you can shore up street confidence in your projection since the recent projections have actually been well above what you have performed?

Let me make a comment, and then I'm going to have Pat add some real color to it. We did not guide up on the power plant performance. What we did is indicate what we expected and what it would take to get the low end of the range for that guidance. In reality, it's absolutely correct that the units did not perform as we expected and a lot of this has to do with, these are old units that are at the end of their cycle before they're going into major maintenance. That is what happened at Four Corners. And it's what triggered a number of tube leaks at the San Juan plant. The other major piece was San Juan 4, which was down for a major overhaul and all of the environmental equipment installation, and particularly the installation of a completely new digital control system. The transition did not go nearly as smoothly as we expected, or as we had hoped, and it took -- that outage had to be extended significantly. We have learned from that process, and Pat talked about the root cause work that was done, to make sure that those learnings go forward on the other two units that are going forward this year. Pat, you want to talk about the reason for increases?

At San Juan, as Jeff mentioned, we had a digital upgrade on Unit 4, along with the environmental outages, and the digital upgrade did not go as we had planned it to. What we did is we have gone outside and gotten a root cause firm to look at the digital upgrade to see what changes we could make. As a matter of fact, we pushed off the outage on Unit 3 this year for about a week so that we could make the changes that were recommended in that. And we're also going outside and getting some more bench strength out at San Juan. Unit three is the only outage this year that also has a digital upgrade. The other two units will not have digital upgrades associated with them. And as we mentioned earlier, the work that we're doing on the tube leaks as we go through and do the environmental outages will help fix the root cause of most of the unplanned outages at San Juan.

Four Corners, the reason that EAF does not look as good in 2008 as we would like is because of that major 100-day overhaul that that unit has. But again, that is a 40-year-old plants and it needs that overhaul. When we see that overhaul done, we'll get to 13 percentage point EAF improvement in 2009.

Palo Verde, despite the fact that their one outage was longer than we had thought, made major progress. There EAF was up about 7 percentage points in 2008 -- or excuse me -- 2007 from 2006, and we expected to see it to go up about 6 more points. As we have said, we see positive things happening on the operating side at Palo Verde. We think we're making good progress on EAF. We just think the budget is going to take a little longer to catch up.

Just looking at the potential improvement that you have at the electric utility, should we read that as on a normalized basis, that PNM would have earnings power more or less in the range of let's say $1.85 assuming you were to get the ROEs that are assumed for the electric utilities?

The earnings power that was shown on the last slide relates to regulated utilities. Obviously, it's going to depend on what happens with FCP and the EnergyCo side. We think it could be north of that. But again, I would remind you Paul that we look at that business and I'm not sure EPS is the right way to evaluate that. But it would have that kind of impact.

(inaudible - microphone inaccessible)

Yes. Is there one on the Web? Steve?

Just a question on EnergyCo. What was the debt at year-end '07, and what would you expect the debt at EnergyCo to be in 2009 without any new transactions?

(OPERATOR INSTRUCTIONS). (technical difficulty)

With the regulatory lag in New Mexico, is there any impetus on your part to lobby for a hybrid test year? And then the second is, looking at '08 to '09 guidance, could you break down in a little bit more detail the accretion you expect from the Caprock acquisition? I guess I would expect some interest cost savings with debt reduction, but I'm not seeing that, so that would be helpful.

You want to take future test year question?

We are evaluating the future test year in New Mexico. There's nothing that statutory prohibits a forward test year in New Mexico. One of the small gas companies just filed for a forward test years, it's a very simple case. So we're going to watch and see what happens with that and then look at it for PNM Electric.

There really are rules that allow a future test year, but it's not quite a future test year in the way we would or you would typically think of it because it has true-up mechanism. And so we're looking at, as Pat said, a full future test year.

The accretion question, as we reported slightly accretive in 2009. If you think of the Caprock business earning roughly 9 to 10% and the gas business under-earning around 5 to 6% and the proceeds net of the Caprock purchase allows us to pay down some debt and we also see some opportunities for investing in unregulated business that would allow for some benefit as well. So that gets us to slightly accretive in 2009.

Let me just make a comment on that gas business. As Chuck said, earning 5%. This is a chronic issue and the difficulty is that most of our revenues on the gas business are volumetrically based and we have declining usage on the residential side because things are becoming more efficient and there hasn't been any new gas gizmos lately. And so that is a challenge that we have tried to push for some form of a decoupling mechanism. I think the Commission will at some point maybe get there, but I think that is a great thing for a new owner to take on.

On the general rate case, obviously the fuel clause is an important aspect and I'm concerned about this other proceeding going on now in New Mexico, this notice of inquiry into the fuel clause, or at least the implementation of the fuel clause. And I was just wondering, has this proceeding gone anywhere, and may it negatively impact the general rate case? For example, it gives the commissioners an excuse not to (technical difficulty) decide upon the fuel clause, your fuel clause, now.

I guess I look at it a little differently, [Maury]. I look at it as the current rules, it would be very difficult for them not to provide it to us, and then if they're going to make any changes to the administration of the overall fuel clause, they would make it to all entities at the same point in time. Now in terms of the status of that proceeding, Pat?

The NOI, everyone filed their comments, they were very similar in nature. They have not done anything with that, they have not even scheduled a workshop. We view that as positive, waiting for our fuel clause to come, and then they could make changes to all of the fuel clauses to make them administratively comparable.

(multiple speakers) that testimony in early December, and so what you're saying is that over (inaudible - microphone inaccessible).

Correct.

We have had comments made by one or two commissioners regarding that this will be something that will take some time to do and would be something that may cause changes to fuel clause adjustments on a prospective basis. So those again are we think good comments to hear.

I just wanted to follow up on the nodal, going nodal and the potential rewards there, and also the potential risks just in terms of getting the software and everything. What should we be thinking about that and how much in place are we on that? Back to First Choice, the customer care, is that totally done with? Are we -- is that (inaudible) [died down] and are we expecting any additional revenues from that vendor, or are we just now finished with that, the new systems in place and we're going forward and there is no other upgrade or anything we have to worry about?

The major systems are in place at this stage and all the Web portals have been done and they're all active and operating well. That does not mean that we won't have continuous enhancements being made to the system, but that is much more on the normal order of business rather than the issues that you get engaged with, with a complete changeout. So no, we don't anticipate additional payments being made because most of the deliverables have really been put there. If they don't perform, however, we have a very good contract that requires -- that has performance measures for both the system and the accuracy of the system as well as their operation of the call center. So if they don't meet those standards, it has a significant impact in terms of their payments to us. It also is structured such that as we add customers, the marginal cost of adding a customer is exceptionally low. And so it would continue to drive down the accounting cost of service.

Sure. And I think from a nodal perspective, we would really see that as an opportunity, particularly with the trading and marketing organization. Our system program is ahead of plan at this stage and likely will be done well in advance of going nodal, except for any sort of fine-tuning that might come out of any final changes in the nodal network. But I think we feel pretty good about where we are and see it as an opportunity.

And just finally, on the synergy savings from the realignment of the merchant business, is that in the $35 million of savings, or is that incremental? And could you just give us a sort of quantifying what that actual number is? Also just strategically, when you look at some of these businesses, they look kind of small. You guys are not the largest company. What is your strategic thought about maybe from the economy of scale situation maybe getting, maybe realigning the business to get rid of one of them or something?

The EnergyCo side is composed of a series of smaller pieces, but in one sense that allows you to be a little more facile with the movement. We now have 1200 MW of generation in the portfolio, we have about 250,000, a little over that, 260,000 customers. And I think on an enrolled basis, we're about 275 or 270, 280 today. I think that gives room to grow. Now there are lots of ways to grow. One is, you put it in with somebody else, and another way is you acquire. A third way is you just continue with intrinsic growth. We have made no decisions about exiting that business, any of those businesses. Obviously we will continue to look at it as opportunities may arise.

Jeff, we have a follow-up question from Sam Brothwell he just sent to me. In light of the weaker earnings outlook and ongoing pressure from credit ratings, is the Board comfortable with the current dividend level?

The Board will be looking at the dividend situation as we move into our Board meeting in February and the Board will take action if any is appropriate at that time. So far, we have not changed our guidance outlook. We think these earnings could support this level of dividend, the question is whether we want it to support that level of dividend. So I will reserve any statement until our Board has had the chance to discuss it in more detail.

I think we're starting to push on the sessions that we have scheduled as one-on-ones. What I would suggest, if you have any follow-up or further questions and if we don't have a meeting with you, please talk to Gina or Frederic or [Francina], although I'm not sure she is here right now, and they can probably answer your question or they can schedule a time to be able to follow up with you.

Again, I very much appreciate the time that you spent with us today and we look forward to working with you in the future.

That concludes today's conference. Thank you for your participation, have a good day.