PNM Resources Inc (PNM) 2007 Q2 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the second quarter 2007 PNM Resources earnings conference call. I will be your coordinator for today. At this time all participants are in a listen-only mode. We will be facilitating a question-and-answer session towards the end of today's conference. (OPERATOR INSTRUCTIONS)

I would now like to turn the presentation over to your host for today's conference, Ms. Gina Jacobi, Director of Investor Relations. Please proceed, ma'am.

Thank you, everyone, for joining us this morning for a discussion of the company's second quarter 2007 earnings. Please note that the presentation and accompanying materials for this conference call as well as supporting documents are available on the PNM Resources website at www.pnmresources.com. Joining me today are PNM Resource's Chairman, President and CEO, Jeff Sterba, and our Chief Financial Officer, Chuck Eldred, as well as several members of our executive management team. Before I turn the call over to Jeff, I do need to remind you that some of the information provided this morning should be considered forward-looking statements pursuant to the Private Securities Litigation Reform Act of 1995. We caution you that all of the forward-looking statements are based upon current expectations and estimates and that PNM Resources assumes no obligation to update the information. For a detailed discussion of factors affecting PNM Resources results, please refer to our current and future annual reports on form 10-K and the quarterly reports on form 10-Q as well as other and current future reports on Form 8-K filed with the SEC. With that I will turn the call over to Jeff.

Good morning, and thank you also for joining us today. It is obvious that we had a disappointing quarter and year-to-date so far. We saw a convergence of a number of issues that combined have created a set of unacceptable results. Ongoing earnings per share was $0.13 compared with $0.25 in 2006, and on a year-to-date basis ongoing earnings was $0.52 a share, down $0.11 from last year. Regarding the gas rate case, you probably know that we have filed an appeal directly to the state supreme court. I believe our employees have done a tremendous job of controlling costs where they can in a rising cost environment, but the utility is facing significant cost increases in the fundamental building blocks of its system. We feel strongly that some issues have to be addressed by the supreme court in order for us to sustain levels of service while expanding the system to keep up with growth.

On a positive note, we've made considerable progress executing the strategy of our JV with Cascade. As you're probably aware, EnergyCo just entered into an agreement with NRG to build a 550-megawatt unit within ERCOT's Houston zone. The JV also closed on its acquisition of the former Lyondell Cogen facility a couple days ago, and I will return to the JV and its strategy in a little bit. But as you saw in our news release yesterday, we also are lowering our 2007 earnings guidance. We have a new range of $1.30 to $1.40 per diluted share, down from the previously stated range of $1.80 to $2.00 per diluted share. Let me first go through some of the major operational issues that we've had occur. Chuck will then go through earnings and revised guidance in more detail, and then I want to focus on what we are doing to address these challenges.

Moving toslide four, this depicts the major drivers that affected our earnings compared to last year. Now, Chuck will go into this in more detail when he discusses the year-to-date walk across, so let me just focus on three key drivers. First, on plant performance, while favorable to earnings compared to last year, due to the considerable improvement at Palo Verde, overall plant performance fell below our expectations. If you turn to slide five, you will see that San Juan has continued on track as a top performing coal plant though we have had some forced outages that we're continuing to try to minimize. Four Corners, however, was a different story with either of the two units off line for almost the entire second quarter. You have to recognize this is a 40-year-old plant that is set to go through a major maintenance cycle, but extended outages were required on both units due to major corrosion fatigue in the low pressure turbine which totaled over 100 days of outage. As to Palo Verde, I have confidence in the new management team and the direction they're taking.

However, the loss of regulatory margin at the plant has placed the unit on a very short leash that causes both planned and had forced outages to be subject to significant risk of slippage. So an original 39 days scheduled outage on unit one was extended to 62 days, and a forced outage on unit three that may have normally taken seven to ten days lasted 22. While overall plant performance is improved over last year, it was below our expectations, and it is below what we believe will be the future normal operating status of the generation fleet. Going back to page four, the second major item I wanted to talk about is weather, which I think you have probably heard reiterated by other entities in this region. We had significantly cooler temperatures in both Texas and New Mexico which impacted all of our operating units. New Mexico cooling degree days were down about 30%. Overall Texas cooling degree days were down about 20%, but about 30% in the Houston area where we have a significant amount of load. In total, weather contributed $0.03 of reduction in our regulated operations, and probably another $0.02 to $0.03 of the $0.07 quarter-over-quarter variance for FCP that is indicated on the slide.

Last, let me address First Choice performance which experienced a slower growth quarter compared to 2006. Now, remember that 2006 performance was truly exceptional caused in large measure by a number of forces coming together during the last year of the price to beat mechanism, forces that are not expected to be repeated. I do believe FCP is on track to meet our over-all expectations for 2007. On slide six, we talk about some of the both negative and positive drivers that affected First Choice Power's second quarter performance. Their overall use per customer declined 12% from last year in the second quarter. The two primary reasons, first, the weather which I already discussed, and second, the First Choice Power has experienced an expected change in customer mix as there is growth in customers outside the native service territory which creates growth at a lower gross margin per customer though still an acceptable gross margin. Realized unit margins were in the low 20s per megawatt hour, in line with targeted expectations.

Beyond weather and customer mix, higher purchase power costs were also an important factor where settled gas prices in Q2 were about $7.55 versus $6.79 per million in second quarter of '06. Mitigating these negative drivers was overall growth in customers year-over-year of about 8% and lower operating costs. Moving to slide seven, while First Choice Power's second quarter earnings were below an exceptional year last year, several key factors are positioning the Company for increased profitability going forward. First, we survived the legislative session without any significant changes to the ERCOT market model. That has removed regulatory uncertainty which has lingered over the market since the beginning of the year and I believe hindered customer switch rates. Second, 100% of the total supply requirements are hedged for Q3 at a gas price of just under $7.00. For Q4 100% of our fixed price contracts are fully hedged locking in $15.00 to $20.00 margins and our variable price contracts are about 50% hedged at a gas price of roughly $7.75.

Last, during the first half of the year we were dealing with a delayed switch-over to a new customer information enrollment and online customer care system with Alliance Data. This system will enable better customer service, improved customer retention and stronger credit management while improving customer operations costs. While originally scheduled for the first of the year, its implementation was delayed until July thus impairing new customer marketing efforts. The conversion is now under way with promising results. New enrollments in July are almost double what we were able to handle during the first half of the year and back to the levels that we experienced in the summer of '06. Let me turn it over to Chuck to discuss financial results and our revised guidance in more detail.

Thank you, Jeff, and good morning. If you will turn to slide number eight, I would like to talk through the year-to-date walk across. Typically we don't show mark-to-market losses or gains and amount of earnings so keep in mind our earnings do reflect our net position in mark-to-market losses in this case. I want to point out that the mark-to-market impacts of First Choice were $0.05 down and PNM wholesale down $0.07. But I would like you to turn to the next slide, because I really think it is important to talk about the mark-to-market changes relative to thebusiness and how we operate the business to reflect and understand how we realize those potential losses or gains as it may be. In the case First Choice you can see was minimal impact of 2007, $0.2 million, and in PNM we had $11.2 million or $0.09 per share that affected (inaudible) PNM Resources in 2007. What I want to do is talk about the hedging strategy that we entered into in January that we were preparing for the following kinds of assumptions.

We saw natural gas prices increasing, above normal temperatures were predicted. We thought that an active hurricane season was anticipated, and as Jeff pointed out we were concerned about the performance at Four Corners and certainly Palo Verde given the increased oversight of NRC. As we went through the assumptions and looked at the situation as it stood in April, we reviewed again our summer strategy of how we need to ensure that we could rely on the base load plants, ensure that we have reliable load to serve our customers. We didn't see at that point any improvement in plant performance. We predicted higher customer load, saw higher gas prices and spark spreads and above normal temperatures. So as a result of this we entered into a hedge strategy going into the summer to protect ourselves against the exposures of our base load plants not being available. We were long power during the summer which give us a little upside opportunity in the event we needed to use that power to serve load. As it turned out, given where we are in the summer, we've actually used the load, managed that position effectively and resulted in certainly market conditions having changed as a result of today with the temperatures being low in the West and the Southwest and ERCOT where hurricane activity hasn't materialized and prices decreased in the west and natural gas prices being lower.

Certainly you can say, well, if we had stayed with a spot position going into the summer we would have come out at a lower costs, but that wouldn't have been a prudent nor do we manage our business in that manner, so as it is we had a strategy going into the summer based on the conditions and assumptions I referred to and as a result of that, we basically will experience an increase in energy costs and low margins as a result of that. Certainly as I will point out again, and probably again, the fact that we have no fuel costs impacts us in regards to how we are able to execute and mitigate some of the strategy. Going back to the year-to-date walk across, I would like to hit some of the highlights that drive the business. Wholesale marketing activity, a loss of $0.08, and I talked about this in the last earnings call. This is mainly driven by a favorable forward sale we had in first quarter of '06 that was not reported in 2007. I mentioned here briefly the coal costs was a loss of $0.06.

And we've talked about, Jeff made some comments about increased commodity prices, steel, fuel, etc. We've also had increases to comply with new federal safety regulations that have caused the coal prices to go up. And for the first time, we are going to experience two long-wall moves in '07 which will increase overall yearly coal costs by $4 million. Although we are currently working with San Juan Coal Company to mitigate some of these impacts, the coal costs remain a concern beyond what we had originally expected. Dilution slightly over 9 million shares at 13.1% increase. This is from the common stock offering we had in '06 and also use of our dribble program. Financing we had was down $0.04. That's an increase in commercial paper borrowings as well as the rates in commercial papers itself, and in addition to that we're paying down our short-term debt with an ending balance decrease from $843 million in June 30, '06, to $560 million as of June 30, '07. We also had some long-term debt we refinanced in April that was variable rate tax exempt fixed to long period of maturity at 4.8%.

On the upside First Choice if you exclude the mark-to-market and dilution was up $0.03 although they experienced a tough second quarter, their first quarter was strong, and it resulted in a year-to-date comparison of a positive $0.03. On the retail load growth for PNM electric, PNM gas, TNMP and weather was $0.09, positive loadgrowth was $0.05. We continue to see customer growth at 2.2%, electric customer growth at 2.3% and load growth at 2.2% and TNMP customer growth at 1.4% and load growth about 1%. Weather contributed $0.04 of that $0.09 positive. Plant performance at $0.14. We did see an improvement at Palo Verde, $0.20 of the equivalent availability factor was below our expectations which were set at 85%, year-to-date it has been about 82%. San Juan has had good performance, similar to last year with $0.02, but with the increased outages at Four Corners we lost $0.07.

If you turn to slide ten, I would like to go ahead and break this down by segment, and again these numbers do reflect the inclusion of mark-to-market and dilution. PNM Resources down $0.11 to total $0.52. The drivers, PNM Electric decreased $0.02 to $0.20. At the beginning of '07 we've talked about we transferred the TNMP New Mexico operations to PNM which added about $0.02 EPS, load growth added about $0.03 to EPS, Palo Verde performance added $0.09. Although these were positive drivers, they were offset by Four Corners availability of negative $0.04, decreased coal costs of negative $0.05 and higher dilution impact of $0.03. PNM Gas increased $0.04 to $0.12. That's primarily the result of increased sales volume driven by colder weather and customer growth. TNMP Electric increased $0.01 to $0.07. That's driven by load growth increasing EPS by $0.01. We began collecting the stranded costs in Decemberof '06 which increased EPS by $0.02 and as I mentioned the transfer of TNMP New Mexico operation unit was a loss of $0.02.

On the wholesale side of the business, EPS decreased $0.10 to $0.11. Once again we saw the impacts of plant availability in this segment although we saw improved performance at Palo Verde increased EPS by $0.11 and poor performance at Four Corners offset the impact by $0.03 and the coal costs off set by $0.01, and as I already talked about and previously discussed mark-to-market impact of $0.07 and other wholesale activity $0.08. Dilution here was $0.02. On First Choice we decreased earnings $0.04 to $.16. That includes again mark-to-market dilution and on the segment level when adding these back into it the overall comparison to last year at a loss of $0.04. EnergyCo, which we'll start to break out on unregulated operation, as you recall, we established in June 1 '06, it contributed $0.01.

I would like to turn to the next page on 11 and discuss the 2007 guidance. Our current performance to date is being revised with projections going forward. We decided to lower the guidance for the year from the range of $1.80 to $2.00 to the range as Jeff pointed out, to $1.30 to $1.40 and I want to again touch on the drivers that impact our decision. At the beginning of the year we announced guidance at the higher level and expected to achieve about 45% of these earnings or $0.85 to $0.95 of EPS in the first half. Year-to-date we only achieved $0.52, or about 29% of the expected earnings. Again, the number of reasons that we fell short were the lower than expected plant availability and performance at Palo Verde and in Four Corners reduced our earnings expectations by $0.15. Higher than expected coal costs with $0.05 to earnings. We anticipated some increases in coal prices this year but not to the degree that we experienced and once again I will point out without a fuel clause, we take the impact. We're still working with the coal company to try to mitigate some of these increases going forward.

The mark-to-market losses also impacted the first half, and I talked about the rationale behind these losses with respect to even though the mark-to-market losses will be reversed with the positions that we have that we took to protect ourselves against the loss of base load plants resulted in higher energy costs and lower margins, and lastly in the delay in the implementation of gas rate increase which we expect in first half of earnings that would have gone into effect in April rather than July 1. Turn to the next page, let's look at the remaining half of year as we reforecast the rest of the year and take into account some of the issues we faced earlier in the year. With our original guidance assumed that we would earn the balance of the year $0.95 to $1.05 for the second half of the year. We're dropping this guidance for the second half of the year to $0.88 due to a number of key factors, mainly the factor affecting our decision to reduce guidance with plant performance. We continue to expect some operational issues during the remainder of the year and also being very conservative in our equivalent force outage rate assumptions, the start-up of Afton originally was scheduled in mid-summer. We currently have a delay of that in mid to latter part of August primarily driven by some late design changes. Delay is expected to cost us $0.04 and reflects the opportunity cost of not having the power available for sale, the wholesale marketing group and the higher cost of purchase power to provide supply.

We do expect continued overall fuel and energy costs to be higher during the second half, higher costs expected to reduce earnings by $0.04 versus our original expectation, and lastly, the gas rates itself impact the balance of the year to $0.02. Total of these factors reduced our earnings by $0.17 versus our original expectations. Many of the issues that affected our performance we expect to be limited to this year. However, it should be noted, and it is necessary going forward, that we are fully committed to putting regulatory (inaudible). If you turn to the next page, the last page to summarize we're reducing our guidance to the year to $1.30 to $1.40, and once again about 60% of the drop is associated with issues encountered in the first half of the year, the remainder impacts are due to plant performance issues, delay in Afton start-up, the higher energy costs and the impact of the gas rate case. Once again I want to emphasize our business has strong earnings power but will need to get through a regulatory process that allows us to reach our true earnings potential.

On the next page on 14, there are some other guidance assumptions here to help you with your forecast and outlook for the Company. I mentioned the equivalent rate sensitivity here of plus or minus 2%. We also updated you relative to the gas and Palo Verde on peak prices, and some gas and energy price sensitivity, for example, any change in 10% plus or minus would equate to about an EPS change of $0.05. With that, again, our guidance of $1.30 to $1.40 for the remainder of the year, and I would like to turn it back over to Jeff and talk about the EnergyCo strategy.

Thanks, Chuck. Let me spend a minute on the strategy of the joint venture with Cascade and where we stand in its execution which I think you would agree is moving forward in a positive way. Slide 15 lays out some specifics of this strategy to build a competitive asset-backed energy marketing and trading company. I won't go over all of the specifics laid out, but let me comment on two. The first deals with location. We're currently focused on consolidating a strong position in the ERCOT market as demonstrated by our recent acquisitions and construction plans. We view this as a good market with asset, retail and trading opportunities. As previously discussed we're also looking to expansion in the western markets. PNM is already intimately familiar with and involved in. While we will also explore the potential for other regional markets, they're much of a secondary nature in focus compared to expanding and consolidating in the position in markets that we know well and have already been successful in.

The second one I want to touch on is financial criteria. Our focus is more on discounted cash flow performance than near-term earnings as we've discussed before. Our long-term evaluation targets an unlevered internal rate of return of about 8.5% or better, and I would assure you that we do not allow our folks to bring forward hockey stick projections to justify those IRRs. On a near return basis we look to generate cash on cash returns of 13 to 14% over a four to five-year period, and I would say that the transactions we have entered into so far meet these hurdle rates that I have just gone through. Now, by focusing on IRR and more specifically cash on cash returns, that doesn't mean that we don't expect to see an increase in EPS to PNMR from the joint venture, but rather our focus is rather more appropriately on building long-term cash value. I know some of you were concerned about the dilution caused by the contribution of Twin Oaks in June. This was done to begin the building of the JV in a manner that will add long-term value. That said, any future transfer that may cause near term dilution will have a high hurdle to overcome in order to gain my support.

Now you saw that we announced the development project with NRG, and on slide 17 there is information about this project. It is a 550-megawatt unit at the existing Cedar Bayou facility of NRG, which is about 30 miles east of Houston and in the highly congested and high demand Houston zone. It will be about a two-year construction period, so we expect to have the project completed by the summer of 2009, providing about 270 megawatts of very efficient low cost gas generation. It will have an installed cost of about or frankly a little less than $725 a KW, which is below new construction costs in the Houston zone by a significant margin. As you probably know, this is a constrained part of the ERCOT grid. As ERCOT moves to a nodal system, I believe this location will provide additional value. On slide 17 we note that we also this week closed on the formally on the acquisition of what was previously known as the Lyondell Cogen facility. We will now call it the Altura Cogen facility. And also on that slide is a map that shows the location of the roughly 1200 megawatts of generation that the JV will have in the ERCOT market once the Cedar Bayou construction is complete.

I think you can see we made substantial progress within the JV and we continue to see great potential in what is becoming a diversified, environmentally- friendly portfolio of generation assets. If I move to slide 18 and the gas order that we received late last month, the order provided an increase of about $9.4 million or only about 40% of what we requested, and denied our request for a decoupling mechanism though it held out the potential for approving a different mechanism in the future. This outcome cannot be left unchallenged. It doesn't provide our gas business the opportunity to earn a reasonable return on the capital we have invested on your behalf, particularly given the historic test year, the extended regulatory lag that occurred in the gas rate case, and the absence of any kind of a mechanism to recognize declining use per customer. So we filed a notice of appeal to the state supreme court. You may know that in New Mexico, we have the right to file immediately to the state supreme court bypassing the rest of the appellate process. We understand that the attorney general has also filed a notice of appeal, and we will file our statement of issues at the end of the month, which of course we will share with you at that time.

I want to be clear about one thing, and that is while we have an awful lot of things going on in our unregulated business, our core utility business and its profitability is our top priority at this time. We will do the things that are necessary to ensure that our regulated operation is returned to being able to earn its allowed rate of returns both in New Mexico and in Texas and for all of the properties that we have in both those states. To drive this priority, we previously announced the hiring of Pat Vincent, formerly the CEO of Excel Colorado, to oversee all of our regulated utility operations, and she'll focus on those operations from a regulatory treatment to streamlining operations and everything in between. Obviously she'll have a lot of support from those -- from the other members of my senior management team, and one person that she will be counting on heavily is also new to our company, Jim Ferland, who has joined us from Westinghouse, who brings a wealth of experience in the power plant side. And I think you will find too, while his background is primarily nuclear, his focus on quality, safety, and efficient operations will be seen in the years to come.

Now, some of you have questioned why we did not settle the gas rate case the way we have settled all of the other cases for the past 20 or so years. Well, the answer is because we did try to, but it was clear very early on that the interveners, at least some of them, including the commission staff, was not going to move off an ROE that frankly was not even close to being acceptable, 8.5%, so we felt that a litigated case was our only option. While the 9.53% allowed return on equity is better than the interveners' inflexible position, it is not adequate, particularly given the regulatory lag, the lack of a decoupling or other mechanism that recognizes declining use per customer, and the approach that they took to disallowing CWIP as one mechanism to help make up for that regulatory lag. I mentioned Pat Vincent joining the management team. If you look on page 19 we also identify some of the other changes that have occurred within management. I mentioned Jim Ferland.

I want to recognize Bill Real who has been an invaluable adviser, confidant and member of our senior management team. He has been with our company and its predecessors for 29 years. He has done a wonderful job in representing us in the public and in front of the regulatory agencies, and I look forward to his continued touch with our company because he has always provided great insight. Filling those shoes that Bill leaves behind is Cindy McGill who will take over a number of the responsibilities that Bill had while the regulatory responsibility will directly report to Pat Vincent. Cindy who will continue to report to me and continue to oversee corporate strategy will have a significant role to play on the regulatory front. For those of you that recall Cindy, she ran our regulatory area for a decade, has very good relationships, and has been through the wars from a regulatory perspective in Santa Fe and will bring great value to that.

Finally, there have been some adjustments to the electric rate case schedule, so we also provided on slide 19 what that new schedule is. We will be going to hearing the first week of October, and would expect a decision, the suspension period ends February 21st. There is the potential that there could be up to another 30-day extension of that under the commission rules, so we would expect a decision in the middle to late part of the first quarter of 2008. Let me spend a few minutes in closing on our path forward. As I said, our top priority is returning our regulated businesses to having the strong potential of earning their allowed rate of return. Obviously the electric rate case is a key component of that. We have a regulatory environment that as you know has elected commissioners. We have two new commissioners that came on at the first of the year. With the gas company pending, frankly, we have not been able to engage them to much of a degree and they ended up having to make a decision on a case that they didn't know that well.

While I believe the commission feels that it did an appropriate job of issuing -- in issuing its decision on the rate case, I am not convinced and I am not believe they fully understand the implications, and we will do the things in the best way that we can to help them understand those implications and to understand the perspectives and view point that you investors, who are going to provide us capital to have a construction budget that's about three times the size of what it was over the last five years going forward into the next five years, but your perspectives which I also hope you feel free to share with them directly. Obviously another part of the regulatory environment is the legislative environment because there are times when there are public policy issues that are better addressed from a legislative perspective. We've been successful in this regard. For example, in the the the last legislative session, we helped pass legislation that ensures our recoverability of investigative costs and CWIP and rate base for certain kinds of facilities, particularly clean coal, and large central station solar projects. In addition, that legislation enables a state investment tax credit of up to $60 million per facility, so we have taken -- that coupled with legislation that we passed two years prior to that, which requires that in a CCN process that the rate-making treatment be addressed and not just directly deferred.

We believe that we've got a stronger pathway to help ensure the recoverability of costs that we incur for new generation built to serve our regulated customers needs. Now, the third piece of that prong has got to be operating efficiency obviously. We're redoubling our efforts to drive end-to-end process efficiency and eliminate low value-added work through our Six Sigma and other initiatives. Pat Vincent's primary charge will be focused on streamlining our operations while we will do nothing that impairs the quality of service to our customers or the safety to our customers and our employees, we are going to do the things that are necessary to help ensure that we can earn the allowed return on the regulated businesses. Another key part of that is the capital allocation process, and we have instituted a new process to help manage a growing capital budget that will be constrained by a disciplined focus on capital spending efficiency. This focus will prioritize projects based the on four criteria, shareholder value, corporate responsibility, customer and stake holder satisfaction, and operational execution. All four of those issues have to be addressed in order for us to consider moving forward with a project and it will have to rank within the limitations that we impose on the capital budget.

Now, the second major piece obviously is to achieve growth through our unregulated investments. I am pleased with the progress and the financial returns of our end regulated operations, and we will continue to focus on developing systems and optimization of assets rather than looking for single assets in markets that we are not as familiar with. Our focus is currently in ERCOT, but as I said earlier, we will also be pursuing opportunities in the western United States and on a secondary basis, will look to what may be longer term opportunities in other markets. With that, let's go on and turn to any question that you may have.

(OPERATOR INSTRUCTIONS) Your first question comes from the line of Sam Brothwell of Wachovia. Please proceed.

Good morning, everybody.

Hi, Sam.

Listen, I know you don't have an OID out there for obvious reasons, and we can look at the slides and see some of the drivers that are affecting this year, but two things I wanted to ask you about conceptually how we should think about it. One is the EnergyCo, obviously you're showing an expectation of a positive contribution for the second half of '07, but taking the dilution of the Twin Oaks transfer and what you expect in '08, should we think about that as being neutral, slightly accretive, what have you? And second is the convertibles that kick in sometime next year, if you can give us a little color on that. And then the other question I wanted to ask is, Jeff, you've alluded to the utility, the electric utility, I believe, earning somewhere in a midsingle digit ROE presently. And if you had a fuel clause, how much would that move that number based on where things sit today?

Let me, Sam, take the first half of your first question. Chuck will take the second half, and then we'll come back on your second question. If I can only remember what they all were, Sam.

I will remind you.

Remind me on the first one. It just slipped out of my head.

Just the as we think about EnergyCo --

Never mind. I recall. Relative to what we've shown for '07, Sam, I would fully expect that EnergyCo will contribute more to earnings in '08 than it is in '07, and we will address that as we do give '08 guidance. But the way we've structured that business, the development of the trading and marketing operation, which is just not even getting off the ground yet but will be getting off the ground a little later in the third quarter, we would target without any additional investments that it would be an increase in earnings from the amount that we are showing for '07. Chuck, on the second piece?

Sam, why don't you remind me. I know one is on the equity units. What's the other question?

The equity units, but the other thing coming off of that first point, relative to do you expect EnergyCo net net to offset the dilution associated with the contribution of half of Twin Oaks?

Yeah, actually the impact that we talked about last quarter showed for this year a $0.05 dilution on moving Twin Oaks over to the JV. But going forward in '08 we look at given the fact that we have Lyondell and the growth of that JV itself, we're looking for continued positive accretion towards the contribution of EnergyCo, which would offset any concerns of any leakage of Twin Oaks being over there in the JV, so we're very comfortable with that piece of it. On the equity units, just to give you some idea, this is a lot of information, and I won't go through it here. We can have it on our website or give you more clarity if you call back, but the main thing is we have two tranches, one is the public equity unit and the other is the private equity unit, and certainly based on the stock price, it drives how many shares are actually issued. Given various stock prices, the range could be from 7.5 million shares to as much as 9 million shares, and if you look around where the stock price is today, it would be roughly around the 9 million shares issued, public equity units. On the private side, again, very similar, anywhere from -- that, by the way, the public equity units were $250 million and about $100 million for the private equity units. And so if you look at the sensitivity on stock price, on the private equity units around the $27.00, we would be looking to close to 4 million shares issued, and as you are aware of, that was an investor cascade with that particular security. It is all based on as you know different stock prices and we can give you more detail based on a follow-up discussion.

Okay. And then, Jeff, if you could just address the issue of how much of your underearning is due to not having a fuel clause.

Yeah. I can't give you a number specifically at this time, and the reason, Sam, is because of the interlinkage of our unregulated generation within PNM and our regulated generation in PNM. It is difficult without making a set of assumptions which will drive the answer as to how you allocate those fuel costs and how you allocate revenues from off-system sales. Recall that the deal we have struck and we have operated under now for about seven years and for five and a half years it has worked very well, has been that in return for having a fixed fuel amount, all revenues made from off-system sales above a level that is built into that fixed fuel, come to the benefit of the company. And so it is hard to go back and look at how would we break out the pieces. My sense is that it probably adds 3 percentage points on a very low ROE, but because of that -- the way that the system is currently operated, it is a bit difficult to come up with a specific number. Now, as we go forward, what we have proposed is that we will not go forward with this sharing mechanism that we've had in place. We will have the regulated assets, and they will be treated as regulated assets with a fuel clause, and then we've proposed a sharing mechanism for any revenues made from off-system sales out of the energy of those assets. And so I guess we could do a back cast using that methodology, although we still have to make assumptions about which kilowatt hour from which generator was used to serve which off-system sale.

I know it is complicated, but that is very helpful. Thanks for all the time.

You bet.

Your next question comes from the line of Lasan Johong of RBC Capital Markets. Please proceed.

Good morning. A couple questions. First on the operational stuff, I think it is fair to say that the plant performance or the lack thereof was really the cause of kind of a domino effect on the rest of the operations, which then led to higher energy costs and higher purchase power costs and fuel costs, so if we -- if PNM fixes the operational issues with the plant, is it fair to say that the net effect of what happened in the second quarter would not be as large?

Lasan, that's right. I just would clarify one thing. The plants where we have had less than desired performance are plants that we do not operate. They're operated by APS.

Right.

But certainly as those plants improve their performance, a lot of the other pieces will get better. Now, energy costs are still going up.

Right.

Both on the coal side and obviously the volatility on the gas side, but it also -- it not only helps lower overall serving costs, but it gives us more opportunities in wholesale markets.

Got it. Chuck, given the the current credit situation, are you concerned at all about how you're going to fund Cedar Bayou and Altura, and is there any wavering of commitment on Cascade on the EnergyCo joint venture.

Absolutely not on that latter comment. They're a great partner, and they've been very supportive to working jointly as the business partner, although we provide the strategic part of the business, and they provide a lot of financial acumen to the bottom line as we're both business partners looking to do what we think is best for the growth of that business. They've been very comfortable and easy to work with, and we're very confident that business continues to be proven direction, frankly I would say a little faster than what I intended originally. As far as the funding of Bayou, that's funded within EnergyCo. We had a facility already establish to do provide that. That's capitalized interest so there is no impact to PNM Resources. There is a permanent financing assumption that we play into after commercial operations in 2009, and then there is some slight contributions that we'll make to support the Lyondell facility, roughly around $45 million contribution, and we'll be pursuing which will be our 50% to maintain a cap structure within the JV that again is very, very solid and sound for that business going forward. Does that answer your question?

That's good. On a follow-up question from what was previously asked on the equity units, do you not have to remarket the debt on the underlying equity units?

We do. There is a two-year remarketing period on that that we will actually -- the time the equity units as we receive the cash to pay down debt we'll remarket debt for an outstanding for another -

And you don't think there is going to be any problems with remarketing the debt?

Not at all, no.

That's great. That's great. One other question. This is I guess for Jeff. What exactly are you going to appeal for, look for from the gas rate case at the supreme court? I am assuming one is a higher ROE. Can you tell us what that is and, two, what exactly are the alternative treatments, the decoupling that is being tossed around?

Lasan, I can't go into the specifics, and the only reason is that we will be filing our statements, and we want that to be the record of what we appeal.

I understand.

That will occur I think it is August 29th or so, but we will certainly post out, if not a summary, the entire appeal. Relative to -- I am sorry, the second piece of your question?

You said that the interveners and PNM had discussed potentially --

Yeah. What we had filed for is what I guess I would call a complete decoupling mechanism that would basically be taking whatever the revenue requirements are that are approved and dividing them by revised kilowatt hours as we move forward. So the commission expressed concern that there were a number of moving pieces in there relative to weather, relative to energy efficiency, relative to just declining use because there is no new gas widgets coming out into homes, regardless of efficiency.

Right.

And they've felt that intermixed too many things, and so they declined to accept our filing. However, they did say that they would go forward and I think we will end up with some kind of a work shop with the commission, and the interveners to look at a modified approach that may be acceptable and appropriate to impose in the near future.

Something that will more narrowly focus?

I think they had a concern that it was a catch-all.

Right.

So maybe we focus on the declining use per customer and energy efficiency, and we take out the weather impacts and weather gets addressed in the normal typical rate case method, that would be one outcome.

Okay. One follow-up quick question on FCP. You had mentioned that there was a shrinkage in margin relative to the customer mix changing. Am I to assume there was a lot more industrial customers than you had expected or small commercial industrial customers affected?

No. Well yes, there is a strong growth in our -- what we call our C&I market, but it really is commercial customers, small to mid-sized commercial customers, and so that affects margin because the margins are not as high there. Plus with the growth that we're experiencing and continue to focus on that business, a lot of that growth comes from focusing on those customers that have a tendency to switch, and with those customers you will see slightly lower margins, and so as our customer count grows and we add on the residential side, those lower margin competitive customers come into the mix lowering the average margin. Doesn't necessarily affect the margin on the customers that have a sense of loyalty to FCP, and obviously we're going to try to move those newly switched customers to that same sense of loyalty.

Understood. Looking forward to reinvigorated PNM. Thank you.

Thank you, sir.

Your next question is from the line of Jonathan Arnold of Merrill Lynch. Please proceed.

Good morning. I just wanted to go into this mark-to-market number which as you show in the guidance update was a $0.09 year-to-date loss, and you've mentioned most of that should reverse in the second half, so should we think about that reversal as being embedded within the $0.04 negative energy cost driver for the second half guidance change? Is that where -- and then there is actually a kind of bigger net negative number for the higher energy costs in the second half?

The answer would be yes, you should take that into consideration. As I mentioned, the mark-to-market moving away from that and looking at the business drivers behind the hedge strategy will result into executing those hedge positions with the actual realized losses potentially given where the market ends up and where we execute could very well result in the higher energy costs and lower margins, so we built that into the guidance.

Within the new guidance, is there a mark-to-market number in there or is it clean of mark-to-market, the annual guidance?

It is clear of -- what happens, think about the mark-to-market we have a number of contracts that will expire by the end of the year, and then there are a few that will continue on in '07/'08.

Okay.

We don't know -- I mean in '08/'09. We don't know what the mark-to-market will be on December 31st for the contracts that have not yet settled, so it doesn't include that. But it certainly includes the settling of all of the contracts in '07.

Would you say the majority is 2007 calendar year?

By far.

Definitely.

And I had a follow-up to that which is with the experience you had with the hedging strategy, is there anything you would have done differently given how it planned out and/or that you plan to do differently to manage that risk going forward?

Well, with hindsight being a wonderful thing, if we had known that gas prices were going to drop to the very low levels that they did with an exceptionally cool late spring and early summer, we would not have placed hedges, but obviously we didn't know that. And I think what our folks were focused on, and appropriately so, was to protect against the risk of unplanned outages, particularly at Palo Verde and Four Corners, and what was forecasted to be a potentially volatile period with higher temperatures and the risk of hurricanes in the Gulf, so I have reviewed -- Chuck and I have gone through in great detail the decisions that were made. We're comfortable that they were appropriate decisions. We will obviously continue to work to look at other instruments that may be more effectively utilized at different points in time, but we are comfortable and I would also say we've gone through this in detail with our board and they are also comfortable with the decisions that were made.

Okay. One other thing related to the EnergyCo, and obviously you made a comment that the contribution from theventure itself would be higher in 2008 versus the number you're now showing for 2007. Is it correct to say that the net versus the dilution from assets that were transferred is a positive number as you take those two together?

Yes. Yes.

Or is it still a negative?

It will be a positive number, and again the strategy as we talked about when we announced the plans was to contribute an asset and look for another acquisition which has occurred through the Lyondell plant and of course the new development with the Cedar Bayou plant, but our continued outlook towards the business is on track to be positive and accretive going forward.

For the elements that are in place for 2008 is the overall -- before you get to Cedar Bayou, the pieces of it that we'll see next year in totality being an accretive or a neutral or a negative?

It would be accretive, and we'll provide more transparency and it is our desire through the the guidance that we provide for 2008 to give additional information on EnergyCo that would give you added comfort to where that business is and what our outlook towards the business is. We're trying to provide that now as Jeff pointed out, giving you some indications as to what the financial metrics are for that business, and what we would look to have for a contribution for 2007, which I think we've shown on one of the slides, it's $0.07 EPS contribution of EnergyCo. So we'll be more transparent in 2008 guidance and give more information, but at this point I think hopefully you'll look at it, as we do, as a positive contribution to PNM Resources.

One final thing if I may, you bring up '08 guidance. Imagine you might not provide that until after the rate case outcome or would you think you would do it before then or give some kind of range indication?

Let me just say on that that you'll see it when we put it out. I am not going to specify what the timing will be. It will be either late this year or early next year.

Thank you, guys.

Thank you.

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

Good morning.

Good morning.

With respect to plant performance and your discussions with APS, do you guys think that you'll be on track in 2008?

I am going to ask Jim Ferland to address it from Palo Verde's side because he has spent a fair amount of time over there since he joined us. Relative to Four Corners, let me just indicate that what we experienced in the first half of the year was a potential failure of a component that had just worn out on an old plant that was about ready to go through a major maintenance cycle. The difficulty would have been caught in that maintenance cycle but it just wore out a little bit before. Four Corners has operated quite well over the last couple of years up until this point in time, and I would expect now that those repairs have been made and particularly with the major maintenance cycle that one of the units will go through in '08, that it will return to the high level of performance that it had been at. Jim, on Palo Verde?

In regards to Palo Verde, significant improvement in performance from last year into this year, quite a bit of confidence in the new management team that APS has put in place led by Randy Eddington. I would expect to see performance continue to increase going forward into the next year or two. Palo Verde did dig itself quite a deep hole, and it will take some period of time before that unit comes back to be a top quartile performer, but I think we will certainly see continued improvement from the the mid 80s on up towards 90 over the next year on two.

By that he means the capacity factor.

Okay. Then the higher energy costs you refer to slide 12, are those at First Choice or are those -- where are those actually showing up, because you mentioned the coal costs in slide 11? I was wondering, higher energy costs was mentioned as one of drivers in the First Choice was higher energy prices.

It is largely showing up in PNM, the utility, and it is associated with coal cost increases, due to the Safety Mining Act, due to steel prices having moved up significantly. We use a lot of steel at the underground mine for San Juan to help shore up the roof of the facility itself, so it is really energy costs largely within PNM but, of course, it also can affect other elements of the business but not to the same degree.

Okay. Then with the First Choice prices -- the customers purchase price cost of the purchase power you had to buy, could you just raise prices on these customers now? I mean, I am just wondering what kind of flexibility you have to increase margins by -- if you're getting higher purchase power prices, can you start to raise prices on them? How do you deal with that going forward or is that something you're going to have to eat due to competitive reasons? And I notice on page four of the earnings release or the data release, that there was a substantial decrease in the three months ended June on customers -- TNP customers who had chosen First Choice, are those legacy price-to-beat customers or has there been some discounting there with price-to- beat customers? I know there was legislative move and stuff. Could you give us a little feel on that?

Sure. I will have Jeff Weiser who is the President of FCP address the second piece of that, and really he can address the first piece which is the question about how if you've got prices rising, how do you balance price increases to your customers and the number of customers you have.

Thanks, Jeff. With respect to the customer opportunity, we look at the market on a daily basis, and we incorporate those cost pressures in the competitive market in our margins, and we see that consistently, so we are able to generate ongoing positive margins consistent with pricing. With respect to your second question which was a churn question, we've experienced in the TNP territory churn in the range of 7 to 10%, varies by quarter, over -- on an annual basis over the last two years, and so there was not a difference as you indicated in our experience in Q2.

And that level of churn is the same that's been seen by all of the affiliated reps. Ours has been a little lower and sometimes about the same, other times, so that churn is just something that does happen. Just one thing to clarify also so you understand the strategy that Jeff deploys. When we enter into fixed price contracts, we lock in the margin by locking in both gas and spread, so that we know what we're going to have with that customer. When we have customers that sign variable priced contracts, obviously that price of that -- for power in any month under that contract can vary on the basis of what happens to predominantly gas prices. We will hedge that out as we see opportunities. For example, I mentioned that we're about 50% hedged in -- we're 100% hedged on our variable contracts for Q3, and about 50% hedged for our variable contracts in Q4, because it does not make sense typically to lock in 100% this far out.

We have time for one more question, and that comes from the line of Edward Heyn of Catapult Partners. Please proceed.

Good morning. Just had a quick question on the Cedar Bayou. You guys mentioned that the total costs of the plan was around $700 a KW, but it was my understanding is that NRG or your other partner is potentially contributing some other, like the land and some of the equipment. Are you contributing more of the actual cash costs and what are your cash costs on a dollar per KW basis?

That is our cash costs. It is about $710 on the project costs. If you include IDC, it is about $725 a kilowatt. That's our total cash cost into the project.

Okay. And just a quick question on you said once the project is operational, it is about $0.04 to $0.06 accretive, and I think, Chuck, you may have mentioned some capitalized interest. Is there any dilution in the near term from financing this or for going using that capital somewhere else?

No, not at all, no.

Okay. Thank you very much.

There will be no further questions at this time. I would like to turn the call back over to management for closing remarks.

Well, this is Jeff. Thank you again for your time today. The only -- the one thing that I can say that I regret is that at the stock price that our stock is trading right now that I cannot buy for another two days, I remain very confident in the prospects for this business. This is a significant bump in the road that we take seriously. We're going to do the things necessary to right the ship on the regulated side. Obviously the rate case is a major piece of that and that has been the intention. Unfortunately we've had a few things that a fuel clause would have helped take care of that we have not had the benefit of in the first half of this year or will have for the second half of this year. Thank you very much for your time. We appreciate your confidence in what we can do with this business, and we will talk to you in the future. Take care.

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Good day.

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