TXNM Energy Inc (TXNM) 2008 Q3 法說會逐字稿

Good day, and welcome to the PNM Resources conference call. (Operator Instructions). At this time, I would like to turn the conference over to Gina Jacobi. Please go ahead.

Thank you, everyone, for joining us this morning for a discussion of the Company's third-quarter 2008 earnings. Please note that the presentation and accompanying materials for this conference call and supporting documents are available on the PNM Resources website at www.pnmresources.com. Joining me today are PNM Resources' Chairman and CEO Jeff Sterba, PNM Resources' Chief Operating Officer, Pat Vincent-Collawn, and Chuck Eldred, our Chief Financial Officer, as well as several members of our executive management team.

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

And with that, I will turn the call over to Jeff.

Thanks, Gina, and, again, thank you for joining us today on the call. I'm sure that you all have seen the release that we made early this morning. You note that our-- on a GAAP basis, we have losses of $0.06 per diluted share. On an ongoing earnings basis, we earned $0.27 for the third quarter. Chuck will spend more time in going through this in detail, but the major elements that rationalize the difference between GAAP and ongoing earnings are really associated with the write-off at the EnergyCo side of the CAIR NOx credits. The finalization of the FCP, First Choice Power, goodwill impairment which we talked about in the second quarter, and then the ongoing mark-to-market accounting issues.

A year ago, recall that we laid out four key strategic objectives that we had for 2008, moving into 2009 that we were going to be executing on. Remember the first one was to reposition our regulated utilities to earn their cost of capital, and you can see from the results of the third quarter that those strategies are starting to pay off. PNM Electric ongoing earnings are up about 22% year-over-year for the quarter. This is as a result of the modified fuel adjustment clause that got put in place and the rate release in the last rate case. We've previously told you about the filing of the electric rate case in New Mexico, and that-- we'll talk about that in more detail, as well as the rate case in our Texas jurisdiction for TNMP, and I think one of the things that we were pleased to see is the commission agreeing to allow us to modify that Texas case to include the $25 million to $35 million of cost that we incurred in the reparations for Hurricane Ike.

The second major objective that we laid out was that we would focus on our electric businesses, and that meant exiting the retail gas operation that we have within New Mexico. We earlier let you know of the stipulation that we entered into. The hearing and the briefing process on that stipulation has been done, and we expect to see a decision coming forth, a recommended decision, before the end of the year.

The third key objective was to rationalize those remaining merchant assets, unregulated generation assets that sat within PNM the utility. Earlier this year, we entered into holding arrangements for Palo Verde 3, which is one of those unregulated assets, and earlier this quarter, we entered into a stipulation to enable to gas assets, which are the only other unregulated assets within PNM, to be moved into our regulated PNM business and are included in the rate case that we filed about 60 days ago. So, that was the third piece.

And the fourth key objective was to reduce our operating cost structure. There is a lot of aspects of that which Pat will talk about in more detail, but clearly we are continuing to see good performance out of our base-load power plants, which is critical. We're on schedule for the $35 million cost-reduction effort that we announced, and we have now finished the major environmental work at three of the four San Juan units. There is one unit left, which will go into that environmental outage early in 2009.

Obviously, one of the main issues that we wanted to touch on is regarding our liquidity position, and Chuck will go through this in more detail, but we're in a good-- what I would call adequate, liquidity position. Recall that we went to market in May and some people questioned why we decided to go in May. All I can say is that I'm very thankful that we did decide to go to the market in May and issue debt, and, as a result, we've got about $800 million of cash and untapped lines within our credit facilities for PNMR and its subsidiaries, not including roughly $400 million of available liquidity at EnergyCo.

In addition, we, like I'm sure most companies are doing, are going through a thorough scrub of our capital expenditures. We expect that in 2008 we will probably be down about $30 million or so in our CapEx. Next year, the number will be more like $90 million. We will be removing almost 25% of our capital expenditures forecasted for next year, and over the five-year period from '09 forward, we're looking at almost $500 million of reduced capital.

Some of this is certainly recession-caused, but another chunk of it is just being able to really take a hard look at some projects that are somewhat discretionary and deciding, no, we're not going to need to go forward with those projects. I also think we will start to see some capital costs go down over time as we're seeing commodity costs, particularly copper, steel, aluminum, cement, come down 20% to 30% so far. It will take some time for those to translate into component costs, but I think that will take some pressure-- some additional pressure off as we go forward.

Hurricane Ike was, obviously, a significant event for us. While our territory in that part of Texas is fairly small, it was the largest hurricane damage we've withstood, and it affected all of our operations from FCP to TNMP to EnergyCo. But the pre-tax impact, we think, is only about $7 million to $8 million, not inclusive of the reparation cost that Pat will talk about in more detail.

So, all of that rolled in when we take into account Ike, as well as the continued inadequate performance of FCP, largely because of Ike and bad debt and things that Chuck will talk about. We would still affirm the low end of the ongoing earnings guidance range that we have previously provided you.

Let me spend just a moment moving to slide 5 to talk briefly about FCP. We told you at the second-quarter call that we were commencing a strategic evaluation as to what should be done with First Choice Power. We've completed that, and the outcome of that is that we believe the retention of First Choice Power at this time provides the best long-term value for our shareholders. This has obviously been affected by not just what's going on in Texas, but certainly including that, where you have seen a number of our competitors, we've had a number that have gone belly-up and others that have run into significant challenges in the operation of the rep market, but that coupled with the deteriorating credit market, while we had a number of folks that were very interested in the property and believe in the value and the potential for it, frankly, we could not see that we would get an adequate element of value if we were to sell First Choice Power at this time because of a less than conducive market, and so we believe that the best path to value is to recommit to operating that business as effectively as we can.

Recall that this is a business that, for the three years prior to 2008, generated plus or minus $10 million, but roughly $50 million, $45 million to $50 million of EBITDA in each of those years, and has really stumbled this year. So, a lot of our effort has been on refocusing and altering the way in which they operate, their market strategy, their operational strategy as it relates to bad debt and renewals, a whole host of things, and putting in much stricter guidelines for their marketing process and their operational practices.

We think that that will pay off. We're already starting to see significant turns in the performance, but the bad debt issue, which is really as a result of what happened this summer through September, will-- is obviously already in the cards, and all we can do is manage that as best as we can. So, that's where we are with FCP. With that, I'd like to turn it over to Pat to go through the utility operation.

Thank you, Jeff, and good morning, everyone. Turning to slide 7, I'm going to start with PNM Electric, and I think many of you know that PNM, this September, filed its integrated resource plan, which was developed during a year-long public involvement effort that included 19 public meetings and a large amount of stakeholders here in New Mexico, and that plan calls for us to add some more renewable resources, to approximately double our energy efficiency programs, and, very importantly, add the two existing natural gas-fired plants to our energy portfolio.

Those two plants, which are Luna and Lordsburg, were part of that stipulation that Jeff mentioned earlier, an agreement among key parties is going to allow us to move about 357 megawatts of jurisdictional generation portfolio into rate-based at PNM. In addition to moving Luna and Lordsburg, this stipulation allows to inquire-- acquire the beneficial interests in Palo Verde Unit 2, which is about 30 megawatts, and it also allows us to include the recovery of the purchase power agreement, including the capacity recovery from the Valencia power plant that we have here.

We estimate that moving Luna and Lordsburg into rate-based will save our customers about $144 million over the next 20 years, and for purposes of rate-making, those two plants are going to be put in at net book value, which is $38.7 million for Lordsburg-- excuse me, for Luna, and $40.2 million for Lordsburg. Since we had our last earnings call, we also filed a new rate case totaled $123.3 million. That was based on a revenue requirement of $807.4 million. Our new rate-based is $1.6 billion, and our requested ROE in that case if 11.75%. There is a tentative schedule in the presentation's appendix-- most of the key dates occur after the first of next year, and the hearings are set to start on March 30th, and a recommended decision could be given as soon as May 29th.

Last night, as you know, the election took place, and we had some key races up here in New Mexico. Two of the five seats on the Public Regulation Commission went before our voters yesterday. In District 1, that's the district primarily here in metro Albuquerque, we have 98% of the results in, and Commissioner Marks retained his seat with 58% of the vote to Tim Cummins' 42%. I think you know that Commissioner Marks is known for his commitment to renewable energy. He's got a lot of work on getting renewable energy in and carbon planning and he, for example, standardized the use of carbon planning in utilities-integrated resource plans.

The whole Albuquerque metro area went very much Democratic. We have the first Democrat going to Congress from the Albuquerque metro area also. In PRC District 3, which is our northern district, the seat that's being vacated by Commissioner Lujan, who is now Congressman-elect Lujan, Jerome Block, Jr. won. He received 56% of the vote to 44% for his opponent. Mr. Block has experience in banking and title industries, and he is the son of former Commissioner Jerome Block Sr. so we look forward to working with both of those two gentlemen in their new roles. The seats for commissioners King, Sloan and Sandy Jones are up again in 2010. They did not stand for re-election in this time.

Jeff mentioned our improving plant availability, and if you turn to slide 8, you can see that consistently, over this year, the equivalent availability factor of our plant has increased. The weighted average for this quarter is 87.2, which is an increase of-- over 81.5 for the last quarter. We've completed three out of the four environmental outages at San Juan. We are just finishing the unit-- San Juan is going. It is in startup right now, and startup is going as expected. Palo Verde is continuing to make strides on their plant performance. Unit 1 is a bit behind in its refueling outage, primarily due to some equipment issues, and they are scheduled to come back up probably some time next week.

Most importantly, we're currently projected to be under our recovery cap in the fuel clause. As you know, we've got a cap on the recovery of our fuel, and we are currently two-tenths of 1% under the recovery cap in our fuel clause.

We turn next to slide 9 and TNMP. In late August, we filed a rates case for TNMP, which is a distribution and transmission utility in Texas. It is our first rate request in over five years there. We're seeking a system-wide transmission and distribution increase of $8.7 million, which is an increase of 5.6%. This filing helped us unlock the first transmission rate, as it allowed for an almost simultaneous recovery of transmission investment. Of that $8.7 million, $3.4 million is transmission, and $5.3 million is distribution. We have requested an ROE in Texas of 11.25. As I mentioned, we requested 11.75 in New Mexico. The higher rate in New Mexico reflects the fact that we're also a generation utility in New Mexico.

Our filing in Texas is based on a rate base of $399.6 million, and a revenue requirement of $162.9 million. As Jeff mentioned, we have been allowed to amend this case, to seek recovery of the cost of Hurricane Ike restoration. We are estimating these costs to be about $25 million to $30 million. We expect to have a hearing begin in mid-February on the TNMP case, with a final order and new rates in effect in the third quarter of 2009. However, that could happen earlier. Late November we are starting settlement talks with the staff and the other interveners in that case.

We turn to slide 10, that gives you a real good visual look at the damage that our system sustained during Hurricane Ike, and the logistics efforts that took place to get customers restored were very proud of how our crews responded, 1, in terms of our safety record, we had no recordable incidents for our crews or any of our contractor crews during the restoration. We're thankful for the help that we received from others.

Jeff said, this was the largest restoration effort we've had on our system, and we were able to restore 75% of our customers within 6 days, and actually the day after, we had all essential services back on. Within 2 weeks, we had 100% of our customers restored, and despite the conditions they were living under, we had incredible amounts of compliments for our customers and the local officials in the towns that we served. As we mentioned, our estimated restoration costs for that effort are between $25 million and $30 million.

And then, finally, on slide 11, just mentioned, we're achieving milestones on our gas sale. The Attorney General's office, the New Mexico Public Relation Commission and the IBEW and PNM all entered into a stipulation supporting the gas sale. The parties support the $620 million sale price and PNM retaining the gain on sale. As part of that stipulation, if the transaction closes, PNM and the Attorney General have agreed to drop their appeal that we had in 2007 on the gas rate case. The next step from that, we are waiting for a recommended decision from the hearing examiner. The parties had the hearings and filed their brief, and it is now with her to render a schedule.

On the operational schedule, we are very much on track. We have met all of our key milestones. On Monday, a New Mexico gas company made offer letters to the employees from PNM that are going over to the gas company, and they have hired a President to take on the responsibilities of New Mexico gas, and all of the system splitting and customer splitting is going on as established. Pending all approvals, a closing date for the sale is expected to be either late this year or early next year.

With that, I would like to turn it over to Chuck.

Thank you, Pat, and good morning everyone. Let me just add a few comments to what Pat said about the gas sales. As you can tell from her comments, both parties do remain committed to completing the transactions, but in addition to that, there has been a lot of questions on the ability of financing through Lindsey Goldberg and the acquisition of the gas business.

I just want to remind everyone that Lindsey Goldberg did provide a commitment letter for the financing from the lead bank at the time we entered into the transaction, and there has been no issues raised on their ability to provide that financing, and in the agreement itself, there is no financing out that allows them to use that as a reason not to pursue the transaction.

Now, turning to slide 13, I would like just to hit some of the highlights, to give a little more detail around the comments that Jeff has made earlier. Now, for the quarter we have reported GAAP loses of $0.06, which is down from $0.11 gained last year. The losses reflect two non-cash charges, one of which is the EnergyCo writing off for inventory balances-- emission allowances under the Clean Air Inter-state Rules. Our share of that right now is $9.6 million after tax. EnergyCo does still have about $118 million in inventory for other emission allowances that are not related to the CAIR program.

At first choice, we completed our impairment analysis and recorded an additional $7.3 million after-tax charge which related to customer contracts and the trade name. That brings us to a total impairment, when you add to the Q2 writedowns of $147 million, approximately, for the first choice.

As we report earnings, ongoing earnings at $0.27 this year was down from $0.46 last year. You can see from this walk-across the implementation of the base rates at PNM Electric, coupled with the fuel cost revenues added a net total of $0.19 to earnings this quarter. The base rate added about $0.16 cents, and fuel-clause revenues about $0.15. Partially offsetting the favorable impact of the rate increase were lower earnings of a first choice, and EnergyCo-- at EnergyCo, the major driver of the $0.08 decline in EPS was the lower revenue from the amortization of (inaudible) contracts.

You recall Twin Oaks had an under-order contract that generated purchased accounting revenue that expired at the end of September of last year. The first choice in energy co-earnings were also impacted by Hurricane Ike. Increased financing cost, as you're aware, and dilution also reduced earnings. Financing costs were up $0.04, reflecting our downgrade in financing activities. The curve-- earlier this year, dilution is the (inaudible) of the conversion of the equity-linked securities, which reduce earnings by another $0.05. We also incurred a $0.03 hit due to the Lehman bankruptcy at both first choice of EnergyCo, as they terminated their power contracts and sell their forward positions, however, we don't anticipate recovery-- we do anticipate recovering most of those losses during the fourth quarter, and most of the impact pertains to First Choice Power.

Now, I would like to go by the individual segments, starting with the regulated utilities, turning to slide number 14. The financial performance of regulated utilities is clearly shown in the results. EPS was up 22% from $0.27 last year to $0.33 this year. There's no-- the net impact or rate increase in this fuel adjustment clause added the $0.19. Negative drivers affecting performance include higher O&M associated with plant maintenance and scheduled outages, the higher financing costs I referred to earlier, and an unfavorable variance in income from the Nuclear Decommissioning Trust. TNMP earnings were down $0.03 from last year due to two factors, Hurricane Ike, which we estimate reduced margins by about $1.6 million, and lower revenues associated with TNMP's cost recovery, due-- in order-- resulting in a reduction in carrying cost from 10.9% to 8.3%.

Looking at the fourth quarter, I want to point out some factors that could affect the utility's earnings. One, on opportunities, there could be some savings as a result of early completion of the outages that are currently planned, and also we continued to drive (inaudible) out of the business to our business in plant projects. Some of the risk, certainly the weather in New Mexico so far has been milder than normal. If this continues, that could adversely impact the earnings, particularly for PNM Gas, and the other risk is the economy. We're beginning to see some early signs of slowed growth in New Mexico.

Now, turning to page 15, looking at First Choice Power, we incurred EBITDA loss of $3.3 million, which is down from an $11.8 million gain from last year. The major drivers affecting the Company's performance this quarter were the Lehman bankruptcy, Hurricane Ike, lower sales volume and higher bad debt. I mentioned the Lehman bankruptcy resulted in a 3.9% charge due to the termination of Lehman supply contracts and settlement aboard unrealized mark-to-market losses. However, we do expect to recapture about $2.5 million of these losses next quarter, since First Choice will be able to purchase replacement power at lower prices.

Sales volumes were down $0.12 due to increased customer turn, reduced customer growth and the impact of Ike and lower average usage. First Choice's number of customers were down 9% year-over-year from 259,000 to 234,000. We continue to see bad debt expense increase at First Choice of $6.4 million due to higher power prices, increased turn and higher default rates. We expect this adverse trend will-- could continue in the fourth quarter, given current economic conditions.

Looking at some of the fourth-quarter outlook and the opportunities at First Choice, where we anticipate Q4 margins will exceed $22 in megawatt-hours, the (inaudible) market begins to show some stabilization. We believe this is reasonable, given that First Choice unit margins averaged around $22 a megawatt-hour in the third quarter if you exclude the impact of Lehman bankruptcy and Ike. We also expect a roughly, around 2% increase in customers by year-end compared to third quarter. On the downside, at First Choice, given economic conditions, First Choice could see higher customer default rates, resulting in increased bad debt.

I would like to EnergyCo on the next slide, slide 16. On 100% basis, EnergyCo EBITDA was up $7.5 million. Looking at some of the positive drivers, they have very strong plant performance at Twin Oaks, which allowed us to earn contractual bonuses of $2.5 million, favorable to Twin Oaks pricing, which also added to EBITDA, EnergyCo was able to sell its uncontracted 25% outputs in the market at higher prices, and Altair and Cogen contributed incremental-- roughly a little over $2 million in EBITDA because of the one extra month we had Cogen operations this year.

On the downside, Hurricane Ike reduced earnings by $4 million due to lost sales opportunities and low wholesale prices, but there were no permanent physical damages as a result of Hurricane Ike to the physical assets of EnergyCo. The Lehman bankruptcy, I mentioned earlier, had an impact at EnergyCo, $1.1 million, but the Company does anticipate they can recover the loss in the fourth quarter through additional power sales. Opportunities-- we've improved the liquidity position within EnergyCo through its existing credit facility, which will allow the Company to continue to pursue additional hedging and asset optimization opportunities, and also we have found ways to improve the dispatching of its Cogen facility to offer increased sales of power and accelerate services.

On the downside, although EnergyCo plants have been operating very well, weather, economic conditions and decreased demand for power could adversely affect EBITDA in the fourth quarter. As a result, we are lowering the fourth quarter wholesale power prices as a result of fourth quarter wholesale oil prices being lower. In the impact of Ike, EnergyCo is lowering its EBITDA estimates for the year to $50 million to $55 million, which is down from the guidance range of $60 million to $70 million.

Now, looking at slide 17, I would like to address liquidity. As Jeff pointed out, we consider it to be efficient or adequate. The table shows our liquidity position as of October 30th. We clearly benefited from the-- accessing the market of $750 million of long-term debt that we issues in May of this year. That has freed up our credit facilities. As you can see from this table, the total facilities are $1.4 billion. That includes two facilities that we put in place in May to provide additional liquidity and financial flexibility.

We drew on these facilities in early third quarter to make cash available and also to test the banks. Our net available liquidity as of October 30th is roughly $785 million. Available liquidity is down from the second quarter because we drew down the $240 million from TNMP facilities to fund a debt maturity that expired in September. In addition, we currently expect to pay off the balance from the proceeds of the sale of the Gas business.

We're also getting a lot of calls from investors and analysts concerning the liquidity position and their various scenarios. We've looked at actively running different sensitivities to proactively manage our position, and we're confident that we can continue to have sufficient liquidity.

I would like to turn to slide 18 to walk you through some key financial (inaudible). This Friday, the Company will be remarketing $100 million of equity-linked securities. We've had the option to allocate roughly $80 million to $90 million of this debt back to the Company. There would be two reasons why we would choose or consider to do that. One, given the market condition, and the potential risk of higher cost of debt, the second would be the extra $100 million in debt that we issued in May is-- provided some additional liquidity that, frankly, is like-- almost like a pre-funding of that remarketing of this $100 million.

Second event is the sale of the gas company, which we expect to provide $463 million in net proceeds. As I mentioned earlier, we planned to use a portion of these proceeds to pay down debt, and the balance of these for corporate purposes. In mid-January of next year, TNMP will read through some refinancing, 6.25% re-financings and also 6.125%. We'll be looking to access the market when we feel market conditions have stabilized, but to allow ourself from flexibility of timing for those offerings, we put in place a new $100 million capital markets grid facility which can be expanded by another $50 million.

During the second quarter of next year, the $150 million delayed draw term loan will expire and is not expected to be renewed given the anticipated sales of the gas business. Once again, we continue to proactively manage our liquidity, and we're confident we have sufficient liquidity to support us during the credit market stabilization as we begin to manage through down to this year and next year.

I would like to turn to page 19 to give you some update on guidance. As Jeff mentioned earlier, we're affirming the low end of guidance, including the impact of Hurricane Ike and First Choice Power's performance. However, we could fall below guidance range if weather is milder than normal, or if First Choice Power performs below our expectations. If this becomes a situation, we'll provide you with an update in early December, after November closes. Given we reported year-to-date ongoing earnings of $0.23, the low end of guidance implies that we expect a loss during the fourth quarter. I would like to explain that.

Although we expect an improvement of First Choice's performance, we still anticipate they will incur a loss in the fourth quarter. In addition, despite the rate increase at PNM Electric, we expect higher financing cost, lower income from the Nuclear Decommissioning Trust, and increased O&M due to plant outages would have some downside effect to the fourth-quarter performance of PNM Electric.

Regarding outlook for 2009, let me just mention a few things to ask you to consider as you look through projections for '09. We're currently in the process of developing our own budgets for the next year and updating in a long way the financial plans. As a result, we plan to update you if the outlook for 2009 during our year-end call. I want to point out some factors that I think you should take into account as you model next year's performance.

First of all, as I mentioned, economic conditions could continue to weaken and we could see some slow growth in our load. Given the market's performance this year, we expect the pension expense to increase next year. We feel much better regarding this impact as we get closer to year end when we value the actual fund itself, but currently, given the fact that we were well-funded at the end of 2009, we don't anticipate having to fund in 20-- 2007, we don't anticipate having to fund in 2009, and possibly we would (inaudible) in 2010, although we will see an increasing expense and impact to earnings in 2009 for the pension fund.

Financing costs are expected to be higher when he finance or refinance the $300 million of TNMP. In addition, the results of the two most recently filed rate cases will also impact earnings next year. As Pat talked about, we would expect that the Texas and New Mexico decisions to be implemented by the fourth quarter of next year. Of course, there are factors of (inaudible) gas sales, and last, as Jeff mentioned earlier, we're going through a rigorous analysis of our capital budget, and we're looking to cut around 25% of the five-year capital plan, and we'll provide more details of that at that time when we update you in 2009 guidance. For now, I would like to turn this presentation back over to Jeff to talk about milestones for this year.

Thanks, Chuck. If you look on slide 20, that's the checklist that we've provided you each quarter, and except for First Choice Power and the challenges that we faced with that business last year, all of the other items seem to be moving well on track. Let me just make a few last comments about not just First Choice Power, but also the Texas market. Obviously, the Texas market has gone through a lot of ups and downs through the course of this year, largely driven by the volatility of natural gas prices early in the year by what I will call questionable management of congestion by ERCOT, which I believe they have really focused on trying to improve, and they in fact have improved, substantively.

I think the rep market is obviously an issue of significant concern to the Commission. They clearly understand that the retail market was-- is a key to their market structure, that there are things that probably need to be changed in terms of the rules of operation. We are certainly working hard and suggesting a number of changes that we think can help make it more effective. It's-- continue to believe in that market structure, and what can be accomplished, but we are obviously changing the focus and the direction that FCP is taking, compared to what it had been doing earlier in the year, to help improve its financial performance, regardless of what-- whether we're successful in getting some of the market rule changes that we believe need to take place.

So, I guess, in summary, I think we are making substantive, significant progress in our major initiatives. We're obviously not there yet, and we told you it would take 18 to 24 months, and we believe that we're still another year out, in order to get everything back in line, but our goals of getting the regulated business to earnings its cost of capital, to developing the capacity to move back into an investment-grade credit rating, these will take time, but we're committed to doing them, and I think we're making progress.

With that, we'll open up for any questions that you may have.

(Operator Instructions). And we'll go first to Lasan Johong with RBC Capital.

Morning. Thank you. Nice quarter. A couple questions. Did I hear correctly, Chuck, that you plan to pay down $370 million of TNMP debt in the first quarter of '09?

No, Lasan, it's not paying it down, they're actually refinancing-- there is 6.25 and 6.125 debt that needs to be refinanced, and we're prepared to go to the market. We're really waiting for market conditions to stabilize, so in the next several months, we'll be looking for the opportunity to refinance that amount.

Okay, and that means, interest rates are probably headed up on those--

Interest rates would be headed up on those offerings, yes.

And that's in your expected '09 outlook?

Yes, it will be reflected in guidance for '09. We will provide that information.

And then, on First Choice Power, I think your decision to keep it is probably the correct one, but just curiosity drives me to ask this question-- how different were the offers versus the value you thought First Choice Power was worth?

Well, Lasan, I guess the best way to answer it is, different enough to say it's worth the risk to refocus and retain it. More than that I probably wouldn't give you any sense of specifics, but you know better than I the roil that the market is-- the overall financial market is in, and particularly related to some of the players that are in the retail competitive markets, so just-- this is not a great time to try to sell that property. I think that was generally reflected in what we saw, and the gap between that and what we think this business is really worth was enough to make us want to say we'll hold onto it.

Then the question begets, obviously, in normal-- within three standard deviations normal, weather patterns, typically, First Choice Power is going to be a decent money maker for you. The problem is, once in a while, we have some severe disruptions that cause-- what I would call-- characterize as blowout losses temporarily. The problem is, as an equity investor, you really don't know when that's going to happen and what that means, and so is there a way that you can give us comfort that there's a way to kind of mitigate those kind of blowout risks?

Yeah, I do believe, Lasan, that there are ways to mitigate those risks, and I think there are a number of learnings from our folks in this past summer. Some of the ways to mitigate these risks involve market rule changes associated with bad debt and associated with customer switching. Others of that will involve a moderation or a modification to the customer mix that we have, which is largely, very heavily residential, and one of the things that the Commission did is, they have-- and this happened last Spring, they prohibited reps from taking customers who are on a term product and rolling them over to a term product if you couldn't reach them.

So, what happened is, you automatically moved them to a month-to-month product which, by nature, is higher priced, and obviously has more volatility associated with it, and that, coupled with having probably only 20% to 25% success rate in making contact with customers and getting them to renew for a term product creates higher volatility for customers. We don't think this is a good outcome, so we're working with the commission on alternative ways, whether they be kind of evergreen renewal approaches or others, that will help move more off o kind of month-to-month kinds of contracts and into term product type contracts.

Term product will help take some of that volatility out of the marketplace, or at least out of our performance, because a lot of what happened this year was associated with customers moving into term product, that enormous flyup in gas prices-- we don't hedge out for month-to-month customers, because you don't know if they're going to be there. That's why they're month-to-month, and their prices float. But when the prices jumped as much as they did, a lot of them said, "God, I'm not going to pay that bill," and so consequently, we're racking up large bad debts amount, and on the bad debt side, one of the things that can be done is to create some kind of a mechanism to help ensure that customers just can't switch without some obligation to pay off bills, and that's one of the challenges that exists in the current market in Texas.

So, we've got some ways that I think will help mitigate that, but you're right, there will always be some volatility within this marketplace, but it doesn't need to nearly be what we and others have experienced this summer.

And I'm assuming the change regulatory model is going from a zone system to a nodal system?

I continue to believe that ultimately, that's going to happen. My personal view is that that's going to slow down in Texas. You've got two new Commissioners who are just coming on board, obviously the move to nodal has already been delayed. I certainly don't know what it will be delayed to, but I think it will be longer rather than shorter. But, obviously, we're focused on getting into a nodal market, because that benefits, we believe, our energy co-assets.

Got it. One last question on the economic front. You kind of alluded and hinted to a slowing down in New Mexico's economy. Can you kind of give us a sense of where these sorts of slowdowns are coming from? Industry, housing, service businesses, and what do you think is the net impact on actual contraction in the economic activity, or are we talking about a slowdown in the growth?

No, it's going to be a slowdown in the growth. If you look at New Mexico's economy, it has never, even through all the recessions that we've had going back to '82, which is a pretty deep recession, it has never gone to negative. It just is a question of how much slower is the growth rate.

We're-- like many places, we're seeing a slowdown in housing. We're certainly not seeing the collapse of housing that some other markets are. We have had some industrial slowdown, and I frankly expect to see a little bit more of that, but remember, the economy of New Mexico is fairly well diversified. It's still got a very large federal government element with the labs and with major military installations. Those will not be significantly adversed, but we have high-tech manufacturing that is a function of the global economy. We also have some other, what I'll call more light manufacturing, which is consumables, things like Tempur-Pedic beds and all that other kind of stuff, and I expect to see some of that slow down. But instead of seeing 3%, 3.5% growth rates, we're probably 2% below. A little bit below 2%.

And how, how deep and how far and how long is the real question. So, this is one of the things that Pat and her time are taking into account at this stage is, what does this mean relative to resource acquisition? We've got efforts out today for renewables, what does it mean relative to the procurement of renewables, what does it mean to any other expansion on our gas-generation side. So, all of that is getting rolled in. We need to see a little bit more of the slowdown.

But, typically, what happens is, the New Mexico economy is affected, but it's not as affected by far as the national economy on average. We still have very high employment rates, we're seeing a slight increase in unemployment, but not nearly what you're seeing other areas. In fact, one of the most recent industrial additions into the economy is having difficulty hiring people for their startup, which is supposed to occur early next year.

Pat, anything you want to add on that?

I think you got it, Jeff.

We will go next to Paul Patterson with Glenrock Associates.

Good morning, guys. Can you hear me?

Yes.

A couple of things. First of all, why did the First Choice customer count go down? Was that simply bad debt expense? And, exactly what sort of is affecting the fourth quarter? Is it just effectively, again, bad debt is going to-- the margins just don't keep up with bad debt, or is there something else we should be thinking about here?

Well, let me take that, and I'll let Chuck add a few points if he wants to on the second part of our question. First, in terms of customers going down, part of it is just conscious. What we've found is that a lot of our, what we call passive enrollments, is the customers that move onto our system, they come in and buy from us, but we haven't actively solicited them to become a customer. A lot of them are at-risk apartments. They're not very good credit customers, they're-- but they might be just above the threshold. They have a tendency to move quickly because they may not be in the apartment very long. What we've consciously done is moved away from trying to serve those customers.

So, we are willing to lose a lot of those as customers and focus on our term products. So, we expected to see, and by expected, I mean, since the early summer, we expected to see some customer degradation in terms of numbers of customers as we altered, consciously, the marketing strategy of First Choice Power. Now, it's-- I would tell you that it's turning, and in this last month, we've seen a net increase in numbers of customers, but it's more focused on the customers that I think we will want for the longer term.

Relative to the fourth quarter, certainly a piece of it is bad debt, but the fourth quarter is never a strong performance quarter for that retail marketplace. It hasn't been in any of the years. It's-- the second and the third quarters are the stronger performance years, but we are-- remember that a lot of the bad debt that is really created in August, September, becomes 90 days past due in the fourth quarter. So, yes, bad debt will be a piece of it. A significant piece of it. Chuck, anything you want to add on that?

No, it's-- just think that, just as Jeff said, that as we go forward and we're in the process of executing more aggressive plans to lower the turn rates through renewal programs and in addition to that, looking to try to extend, as Jeff talked about earlier, turns of customers as far as changing from month-to-month to longer periods of time, and it just takes time to execute those plans and address our exiting, given the challenges we've had earlier this year and in the summer months of high commodity prices trying to work through getting those plans implemented to stabilize that business.

But, although we will see some improvements in the fourth quarter, we won't be out of the woods in the fourth quarter, and we'll begin to see those improvements more significantly in 2009 as we restabilize that business.

Now, you mentioned that the First Choice, that there was an issue with bad debt customers simply going and switching suppliers and I guess effectively just leaving you guys with bad debt. Generally speaking, in most commercial marketplaces, people deal with that in terms of credit ratings or something of the sort. There is some predictable way of dealing with it. There is not usually some mechanism, I guess, to go to the Commissioner and ask them to somehow take care of it. Could you just elaborate a little bit more on that?

Well, now, you're absolutely right, and a lot of it is done through the credit side. What we're working on, and I'm not going to go into a lot of detail on it, but is a much more focused set of credit metrics, because typically you'll end up with people that-- they just basic FICO scores, and what we're finding is that that's not necessarily as good a predictive of bill payment behavior as others.

But what happens is, someone says "Okay, I've got $300, I'm not going to pay the electric bill, I'm going to pay the deposit to go to someplace else." And so you end up with this churn that causes a friction across the business. The-- so, credit scores are clearly one of the tools, and the development of deposit payments to be made are one of the key tools.

Well, for example, let me give you an example, though, of where we find credit scores not necessarily being predictive of behavior. We have established a pretty strong position within the Hispanic market, and if we look at raw credit scores, frankly, they are not at the same level as we-- as you see in other parts of the marketplace, yet their payment behavior for-- to First Choice Power is much better than other market segments. So, that's where we are working on tools that will be more predictive of payment behavior for electricity, because traditional FICO scores, we just don't think are.

Really briefly, the TNMP ROE for the last twelve months, what was it? And what-- I looked at the appendix, but I'm afraid I just missed it, what is the equity ratio in the (inaudible) structure that you guys are proposing in your 8K?

Pat, you want to take that?

Yeah, the-- if you turn to-- just a second, let me get to the page, the TNMP, the-- page 10, in the last allowed ROE at TNMP Texas was 10.25, and the debt/equity ratio is 60/40.

60% equity?

60% debt.

The debt is 60%.

Yes.

Okay, and what is the last twelve-month ROE? I mean, in other words, what are you currently working at TNMP right now? If we take the last-- whatever the last numbers you have available?

We haven't calculated that for you, but we can get that to you.

Okay, great. Thanks a lot, guys.

We'll go next to Paul Fremont with Jefferies.

Thanks. If I look at your slide 20, I'm just trying to figure out if that last checkmark implies that you may need to file another rate case, and I guess my question would be, your past year probably goes through March of this year. To what extent do you have the ability to update known and measurable changes in cost into your current filing? Or would you have to wait until a new filing to sort of catch up?

Pat?

In New Mexico, we have a 150-day know and measurable adjustment, so we have made all those known and measurable adjustments. We have also, in this case, asked for some more of the San Juan environmental upgrades that are outside of that 150-day true-up because they are not revenue-producing. So, we have done known and measurables all the way up until August, plus the San Juan.

So, I mean, does that imply-- am I reading that correctly? That there are expense increases that you're now anticipating post-August that will put pressure on the expense side of your income statement next year? Which you would have-- which would then potentially cause you to file another rate case after you get the result of this rate case?

We filed for a fuel clause-- the extension of the fuel clause in this case, and that fuel clause is a prospective-looking clause, and the calculation in there is a twelve-month forward-looking from March of this year. You are always going to have T&D capital investments that are outside that 150 days, because if we get new rates, they would go into effect at late summer of next year, so you're always going to have some regulatory lag, but by taking forward the 150 days, plus the San Juan and the fuel clause, we're going to start to minimize that. Obviously, the decision to file another rate case also depends upon the outcome of what you actually get in that rate case.

Okay, and then my other question is, back in February, you identified PNM Electric rate-based as $1.8 billion expected, I guess, for 2009. Can you update that number for the stipulation, or give us a sense of what you would expect rate-based to be in 2009?

Paul, this is Gina. Just to clarify, you're talking about the earnings power slide that we presented?

Slide 36 of the February presentation.

That would be the earnings-- the earnings power slide.

Right, but I think it gives an estimated rate-based number for PNM Electric.

Yes, that's correct. That was the $1.6--

When we filed it, this last rate case, it was $1.6 billion was our rate-based.

[crosstalk]

We're going to update that when we do guidance for '09. We'll go back and we'll update that slide, because I think we just want to make sure we have the most current information and let the budget process and some things settle for this year, and then we'll provide that information.

Paul, the earnings-- just to keep in mind that $1.8 billion, which I do recall on that slide, that's a year-end '09, and it was based largely on the old capital budget, which we talked about that we're cutting fairly substantively. So it will be updated.

And I guess the $1.6 billion, do I need to add the $78 million for Luna and Lordsberg?

No. That's in that $1.6 billion.

That's included in the $1.6 billion. So, there are no adjustments? Because the-- also the repurchase lease-held interest in Palo Verde is in the $1.6 billion?

That's correct.

So that's-- that number is still a good number as of, what, March of this year?

March plus the five months, so August of this year. Plus, from San Juan-- the San Juan environmental upgrade that we put in there. So, it's basically August of this year plus San Juan. It doesn't have any T&D and other generation numbers past August.

Thank you.

This is Chuck, let me just-- the earlier question regarding 2007 ROE results-- if you just reference in the appendix slide 30, it shows what the '07 results are. We were up the rate based for the-- each of the regulated utilities. And if you access our website, you'll get the details as to the methodology and the calculations. So, I just wanted to add that information.

We haven't calculated them at the third quarter this year, but those are year-end.

I'll take our next question from [Chris Deor] of Evergreen Investments.

Thanks. Well, first of all, a request-- I didn't see a balance sheet or a cash flow statement in your request, and as liquidity is a key concern, I think that would be something relevant to include. Going forward, that would be very helpful. But I wanted to just ask a few questions. On your refinancing, you basically have $460 million at TNMP early next year.

$317 million.

Well, it's-- the bridge is $150 million, and then the two notes is $300 million, and-- so, basically, you're--

[crosstalk]

The bridge is supporting part of that $317 million until we go to the market and are able to issue that permanent debt. So, the total amount of debt is slightly over that $300 million. And also, just to add-- we issued the 10Q this morning, so you can get the details there.

Well, I mean, if I'm looking at TNMP, you've got a rate base of roughly $400 million, you earned 6% on it, yet now you need to refinance $300 million, which is-- given the market, well over 6%, and I mean, how-- how confident are you on the refinancing there?

Well, we're confident-- you know, your point is certainly clear, is that we're confident in accessing the market, but under today's condition, the rate level is the concern, and so frankly, that's the reason why we put these bridge facilities in place is to give ourselves ample flexibility as to when we time execution to refinance our securities in the market. So, we're going to let things sit on the sideline for the next few months and just kind of let the market settle down, but certainly the interest cost will be well above the 6% level. And at this point, if we were to go out the market, then we're probably looking at the levels that wouldn't be attractive to us, and therefore, that's why we want to sit back and wait for a better opportunity and let things settle down, liquidity in the capital markets.

What's the risk that you'll have to refinance it using at the parent level?

Actually, we have adequate liquidity at the parent level and no plans at all to refinance, and just to further substantiate that, as I talked about, we will go to the market with the $100 million equity-linked securities this Friday, but given the fact that we previously financed an extra $100 million back in May of this year at 9.25%, we really don't anticipate that that additional $100 million is absolutely essential, but we'll go to the market, see what the rates are, and we'll make a determination as to, if any, how much we can allocate back to the Company.

In terms of the gas sale, and there's no financing out for the buyer, and-- I mean, if they can't get financing, do they have any other resources that you would have recourse to? Or are you confident that you can force the sale through?

We're comfortable that the commitment is in place by Lindsey Goldberg, and we've had recent conversations and, frankly, know the lease banks, and the bank syndicates that are involved in the financing, and that-- those facilities are committed and in place, and don't see any issues with that.

But is this-- I guess, do you have recourse to the fund itself? Or is this a shell company and-- in other words, just in a worst-case scenario that they can't get financing, what legal entity are you dealing with? Is it the shell company that's doing the buying, or is it the fund itself that you're working with?

Well, the Company is Continental Energy Systems, which is the holding entity of not only the New Mexico gas business, but also the other gas businesses that are owned through that holding entity, but located both in Michigan and Alaska.

I know those companies, they really don't have the resources to come up with this kind of money without the parent support, without the fund support, so, I mean, it's-- well, you can say there's no financing out, but--

Well, you know that-- they're signing out for Lindsey Goldberg to use as a reason to not execute the transaction, and we have both debt and equity commitment letters in place, and recent discussions with both Lindsey Goldberg and the lead banks that have put that debt commitment letter in place has confirmed that they're ready to do the financing at the time we have approval to proceed with the closing.

So, at the same time, we will plan sensitivities around any situation that could occur from a liquidity standpoint, but we're confident that, at this point, we have affirmed Lindsey Goldberg's ability and we're comfortable the financing will take place.

Initially, you-- please correct me if I'm wrong, but I think you were fairly confident you could get this deal done by year end. What would account for the delay? And what's the absolute final date that they have to execute this?

The hearing examiner in New Mexico has a couple other cases. She has the FPS rate case, she now has our electric rate case, so-- and she had some personal time in there, so it's just a matter of kind of regulatory delay. Nothing in particular other than the hearing examiner's schedule.

And what's the timeframe here for closing? Is it 30 days-- I remember in the Alaska and Michigan transactions that your counterpart did, it was 30 days after the regulators made their decision. Is it something similar here?

Chris, this is [Fred] if you call Gina or me later today, we'll give you the background on the transaction. We're out of time.

I think the 30-day timeframe is very reasonable, and what would be our expectation.

So it all depends on the regulator.

Yeah, that's exactly right.

Thank you.

That does conclude our question and answer session. At this time, I would like to turn the conference back to our presenters for any additional or closing remarks.

Well, again, thank you for your time this morning. Chuck and Pat will be out in Phoenix, I'll be there for part of the time, but we'll not be able to be there the entire time, so if you have any follow-ups, you can certainly run into any of us in Phoenix next week, and I don't know how many of you all stayed up last night watching the election results, so you may want to go take a nap. We've got a lot of change ahead of us in this industry, which I think makes it even more exciting. Thank you all very much.

That does conclude this conference call. You may disconnect at this time.