PNM Resources Inc (PNM) 2005 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the 2005 third quarter PNM Resources earnings conference call. My name is Enrique and I will be your coordinator for today. At this time all participants are in a listen-only mode. We will be conducting a question-and-answer session towards the end of the conference. (OPERATOR INSTRUCTIONS). As a reminder this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today's call, Ms. Lisa Rister, Executive Director of Investor Relations and Corporate Planning. Please proceed, ma'am.

Good morning. Thank you for joining us this morning. We are glad to have you on the call. Please note that the presentation material for the conference call and the supporting documents are available on PNM Resources' website at www.PNMResources.com.

Joining me today are PNM Resources Chairman, President and CEO, Mr. Jeff Sterba, and our acting Chief Financial Officer, Mr. Terry Horn, as well as other members of PNM's management team.

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

With that, I'll turn it over to Jeff.

Thanks, Lisa. Good morning. Welcome. Thanks for joining us today. If I think about the third-quarter operations, and you have seen the results in the release that we made yesterday, which was $0.46 per diluted share compared to $0.45 in the same period last year, I would have to say it was a quarter of mixed results. And I say mixed results because if I look at the fundamental metrics of the operation of our business, most of the operations of our business performed well. Unfortunately, it was overshadowed by poor performance of our nuclear resource and one of our coal facilities.

If you look at page three, we delineate three major items that I want to spend a minute on. And the first is one is the downside that we experienced this quarter relative to decreased plant availability. Palo Verde -- and let me refer you now to page four -- experienced about an 8% reduction in its equivalent availability factor for Q305 compared to Q304. And if you look at the table or the bar chart on the top-half of page four, you will see the 2003 through 2005 performance of Palo Verde, and you'll see a fairly steady decline in operating performance.

We have talked about this and I want to spend a moment on it because I do believe that this is something -- well, it clearly has our attention and it has Pinnacle West's attention -- and it's something that I do believe we can turn, but it did hurt us not just in the quarter but in the year-to-date. Because year-to-date, the equivalent availability factor is, obviously, also down about 3.5%. And Palo Verde is, obviously, our cheapest cost resource.

Our second cheapest cost resource is Four Corners where we saw the forced outage rate of Four Corners up about 6% for the third quarter this year compared to last year. So, our two cheapest generators -- generation resources which total about 600 megawatts did not perform as we would anticipate and like them to in the future.

In the third quarter of 2005, this had a bit of a double whammy impact because we lost our cheapest resources at the time that the replacement power costs were really the highest that we have seen in quite some time. If you look at the bottom of that same page four, you'll note that for the third quarter our total average purchased power costs per unit were up about 25%. And for our major long-term purchased power costs, which is about a little over 300 megawatts of long-term power contracts, the energy component was up about 40%. This was largely driven by, obviously, higher natural gas prices, as well as reduced coal availability to one of our major suppliers, Xcel, on the wholesale side because of the limited availability of rail to move ERV coal into their coal generators. So, they experienced reduced coal generation and, obviously, higher natural gas costs. And those costs then became part of our purchased power costs and there wasn't anything cheaper on the market. So, at the time when the generators, our cheapest generators did not perform well, the purchased power costs for replacement power were at their highest levels. And that definitely impacted our performance for the third quarter, as Terry Horn will talk about in more detail.

Let me also make one other note relative to our long-term purchased power costs. The rate of increase that we have seen under some of our contracts, and particularly our contracts with Xcel, have caused us some consternation. And we do have proceedings in front of the FERC at this time to investigate the calculation that is used in the determination of what fuel costs are passed through those contracts. And we can talk more about that if you are interested. But that is, clearly, the biggest disappointment that we had, the decreased plant availability at the time when replacement power costs were at their highest.

That was offset by strong performance in our retail load growth, where we saw about a 6.2% increase in overall sales due to warmer weather, continued strong retail load growth, which were positives to our earnings, and First Choice and TNMP continued to perform quite well and contribute to the bottom line. And if you flip to page five, let just talk briefly about some items in First Choice Power.

We have seen our competitive customer increase -- our count of competitive customers increase about 17% in the last year. And frankly, this was during a period in which there was virtually no marketing by the predecessor company. And we have only started some rudimentary marketing efforts for customer attraction. We have delayed what we have developed as major programs for launch in Texas largely because of the whirl of increased natural gas prices. And quite frankly, until we got some of that settled through the marketplace, it would overshadow anything that we did on the marketing side. So, we deferred those programs. We have continued to see erosion in our price-to-beat customers; they're down about 7%. This is a rate of reduction that is less than that being experienced in other parts of Texas by other suppliers but, obviously, is something that we continue to work on.

Relative to that -- and let me jump down to the price-to-beat -- one of the things that's obviously important to us is the price that we charge for our price-to-beat customers. We have filed with the Commission and we expect action on October 28 that will create a new strike price at just under $11.10 that would go into effect. And the way that we filed this, it effectively was filed as a discount to the strike price that would be in effect through the balance of this year, and then in January 1, 2006 it would automatically increase about $0.30 to $11.38. Again, that's on January 1, 2006.

Obviously, increasing the price to price-to-beat customers, you are concerned about will it further speed up erosion of the customer base. The real challenge there is what's the next best alternative and what's the competitive market going to show. Obviously, competitive market prices have moved up sharply because of the natural gas prices. So, we believe that this approach will maximize the profitability of our portfolio of an increasing competitive customer base and a slightly reducing base in our price-to-beat customers.

One of the things that we have entered into that First Choice previously had never participated in were the capacity auctions in Texas. For those of you that are familiar with the Texas market, you know about this. But effectively, those entities that retain generation, significant amounts of generation, are required to auction, both on an annual basis and then on a monthly basis, a portion of their capacity, their generation capacity into the Texas marketplace. And this can afford the opportunity to pick up both swing power as well as round-the-clock power through the competitive auction. First Choice Power has previously never participated in any of these auctions. We participated for the first time in the annual auctions for 2006. We successfully procured both baseload and heat rate products. And the benefits of those transactions that we were able to make will show in performance results starting in the fourth quarter of '05. We believe that those transactions were quite successful.

The last item I would mention, because it is of concern because of the volatility of natural gas prices, is to what extent are we hedged in our natural gas procurement. And we are about 90% hedged through the end of the first quarter of 2006. Now, I know that many of you, in fact all of you, would like to know at what price are we hedged so you can compare that price to what the price-to-beat price is or what the competitive rates are so you can determine margin and look at our customer growth. If I was an analyst that's exactly what I would want. If I were a competitor, that's also what I would want, so it's not information that we're going to provide because it is information that's very important from a competitive perspective. What I would hope will happen over time is you will see the results of the decisions that we make about our marketing strategies and about our power procurement strategies and how they develop profitability within First Choice Power.

Also recall, for those of you that were involved with us at the time we entered into this transaction, First Choice Power was not something that we paid a lot of money for nor did we have any expectations of significant enhancement to earnings. We, frankly, expected that we would see a decline in the earnings power of First Choice Power in terms of developing the price that we paid for it. I believe that we're going to be able to see substantive growth in the performance over time of First Choice Power as it develops its capabilities within this marketplace. But, we are hedged about 90% through the first quarter of 2006. And again, we do believe that the Commission will approve our price-to-beat strike request. It has already been -- received a nod of approval from the Commission staff.

Briefly turning to page six, let me just touch on a couple of other updates. First, as I believe most of you know, we have closed our transaction for the final $100 million tranche of private equity units with Cascade. That completes the refinancing that was part of the overall TNMP acquisition.

Second, a piece of good news that isn't noted on here, today we will be executing a new power sale of 150 megawatts to APS. This is a 10-year contract for summer-based power. I think it is four months out of the year for the first two years starting in 2007 and six months a year for the remaining eight years of the transaction. Its pricing insulates us from any increases in gas price. And if we look at it relative to Afton -- I'm sorry -- relative to Luna, which is the combined cycle resource that we have coming on line mid next year, this transaction will provide a very attractive rate of return on the investment that we made in that resource. And it also provides us the opportunity effectively to resell this because of the way it is structured. We believe we can find additional energy in the market out of gas units that could serve this sale for -- to secure a good margin for us, which would allow us to effectively then resell the Luna power. So, we are very pleased with that transaction. We will have a separate press release going out probably within the next couple of days.

A third item I would mention which is also in our quarterly press release deals with the Afton turbine. We are in negotiations with the intervenors in New Mexico regarding moving the currently unregulated Afton combustion turbine from the competitive side of the business into the regulated side of the business. And our plan is that we would expand that power plant to a combined cycle one-on-one configuration, which means that we would be putting a steam turbine on it.

We both have a steam turbine in storage, as well as an option on another steam turbine. And we are in discussions about which of the steam turbines will be used. Depending on how that overall negotiation comes out, which I do believe will come out favorably in terms of the move of this resource into the regulated side of the business, we may experience an economic impairment of a generation asset of the steam turbine that we currently have in storage. We have about $24, $25 million invested in this turbine. It was a turbine procured back in, I believe, 1999, when there was a very high demand for these steam turbines. So we paid a good price, if you will, or a high price for that steam turbine. I think it was procured before I had come back to the Company. And it's basically been in storage since that point. Today the market for those turbines is certainly not as robust and its market value is less than what we have in it. We would have to go through an economic impairment analysis and determine what, if anything, would happen. Obviously, it would be a non-cash item. And we will continue to find -- to look for what's the best way to deploy this asset whether it's just sold on the market or whether it is used for generation construction at one of our other sites. But we wanted to make sure that the market understood there could be an economic impairment. I would expect that issue to be resolved in the next 30 days or so.

Fourth, let me just mention that we had a special session of the State Legislature in early October. This was primarily driven by the increase in natural gas prices and the concern -- as well as oil prices -- and the concern about the impact that was having on consumers of gasoline and natural gas within the state of New Mexico. As you may know, New Mexico is blessed a bit in that the increases in natural gas price, while they affect consumers, they also affect the state treasury. Because of the amount of natural gas and oil development that occurs within our state, the level of severance taxes that come into the State are significantly enhanced by these higher prices. And the State is forecasting a surplus somewhere in the $700 to --$ 700 million to $1 billion.

The outcome of this special legislative session is really threefold as it relates to us. First, there are rebates going back to all consumers in New Mexico to help offset the higher cost of gasoline. These amount to about $125 million or so. Second, there has been a special appropriation of about $23 or $24 million of effectively LIHEAP money coming from the State, which is a positive for us because it effectively means that those customers that have trouble paying bills will be able to not only look at the federal LIHEAP program or private programs, including one that we run, for bill assistance, but also another $23 or $24 million that will be available in state assistance.

Now, we also have a provision in the legislation that precludes our ability to turn off natural gas customers for failure to pay bills during four months of the winter. But frankly, that is mitigated by the existence of this $23 or $24 million that will be able -- will be made available to pay for those bills of low-income customers who cannot afford to pay their natural gas bills this winter. And again, let me just clarify that our inability to cut customers off is limited to low-income customers. Our regular credit policies will continue in place for all other customers.

And last, let me just mention that, obviously, we have the upcoming EEI conference. We look forward to seeing you there. Given that we had an analyst session which many of you were able to join us in Santa Fe -- I'm sorry -- in Albuquerque a few weeks ago, and having this call, we have decided that it probably is not that valuable to do a presentation. But we are available to meet with you on a one-on-one basis. Jeff Shorter, the President of First Choice Power, will be with me in Florida. And so, if you haven't scheduled time, I think we do have a few time slots left on Monday or Tuesday morning. Please call Lisa and schedule time for us to be able to get together, because I certainly look forward to visiting with you.

With that, let me turn it over to Terry to go through a more detailed run-through of the quarter financial performance.

Thank you, Jeff. Good morning to everyone. I think I will start with slide seven, which is a reconciliation of GAAP to ongoing earnings. For the quarter, PNM Resources earned $0.41 on a GAAP basis compared to $0.45 a year ago. Ongoing earnings, including $0.05 of non-recurring charges, brings us up to $0.46 cents for the quarter. Acquisition-related charges of $0.04 are associated with severance, relocation and consulting for synergy projects. The other $0.01 is associated with refinancing charges related to the acquisition.

Last quarter we mentioned that we would see the acquisition-related charges trickle in for the rest of this year and 2006 as we finish integrating TNMP. Earnings reflect strong contributions from First Choice Power and TNMP, which helped offset the poor Palo Verde performance, higher gas prices and the higher purchased power costs that Jeff talked about.

On a year-to-date basis, GAAP earnings were $0.92 compared to $1.13 a year ago. On an ongoing basis, net earnings year-to-date are $1.16 compared to $1.13 for 2004. If you remember we didn't have any onetime charges in 2004.

Moving to slide eight, we take you through the major drivers quarter-over-quarter that resulted in our earnings. This quarter is the first time we reported an entire quarter's worth of earnings with the impact of both TNMP and First Choice. And as you can see, both companies had a significant positive effect on earnings.

First Choice Power contributed $0.21 for the quarter. If you are comparing to last year's operation, margin was down 2% from $35.4 million in 2004 to 34.7 million. First Choice revenues benefited by strong growthin the competitive residential class and more cooling degree days. However, those gains were more than offset by the expected attrition of price-to-beat customers and the loss of competitive mass-market and mid-market customers, primarily aggregated Texas city and municipal services.

Competitive customers grew at 11.6% while price-to-beat customers decreased by 7.2%. The increase in margin is somewhat offset by reduced bad debt. TNMP added $0.14 for the quarter, reporting a margin of$ 45.7 million. Again, if you are comparing to the third quarter of 2004, the margin was down 6.3%. You will remember that in May, a $13 million rate reduction took effect in Texas and we saw 6.8 million of that rate reduction during the quarter. This was partially offset by increased usage due to weather. TNMP experienced an increase of 14.8% including cooling degree days, resulting in a $3.6 million increase in additional revenues.

PNM's retail business, our gas and electric operations, saw a $0.07 contribution to ongoing earnings per share. $0.05 is attributed at electric load growth of 3.4%, which is weather-adjusted, and $0.04 for warmer weather as we experienced a 20% increase in cooling degree days. Those gains were offset slightly by the 2.5% electric rate reduction started in September. If you remember, that is the final and last leg of rate reductions through our global settlement, so rates will remain flat on the electric side now through the end of 2007.

Now I will turn to the aspects that lowered our earnings for the quarter. We have broken out financing for the TNMP acquisition separately and for the recapitalization of that company. Financing impacted earnings by $0.12. $0.07 is interest expense related to the issuance of the equity-linked securities and increased commercial paper borrowing at the Holding Company for the acquisition. The other $0.05 is related to the dilution effect of additional shares of common stock issued during the acquisition. For the quarter, we have an additional 69.5 million fully diluted shares ongoing outstanding at this point in time, compared to an average of 61.2 million shares a year ago.

As Jeff talked, purchased power costs were quite a penalty this period. As you can see, purchased power costs also had a negative impact, with our major long-term contracts increasing costs by about 40.5% quarter-over-quarter. $0.05 is related to prices, which really decreased retail and wholesale margins. $0.04 is related to costs required to serve our load. Related to retail purchase costs -- retail purchased power costs is plant availability, or in this case unavailability. The outages at Palo Verde, as Jeff mentioned, limited the amount of excess energy we had to market and forced us to purchase power at higher market prices. The impact as you can see was $0.07. $5.4 million of that was at Palo Verde. $1.8 million was Four Corners.

In the “Other” category, we had $0.07. $0.03 is due to increased operating expenses, including increased pension and benefit costs and consulting costs. $0.03 is the Wood River investment reserve. $0.01 is associated with the expiration of the Navy contract in March of this year. As you will remember, we did renegotiate a new contract with the Navy for 2006. We have $0.06 in increased depreciation resulting from additional assets in the T&D business, gas business and additional plant assets of a total of $125 million.

If you will turn to slide nine, I will walk through the drivers year-to-date. Again, strong contributors to EPS were First Choice Power and TNMP. First Choice added an additional $0.28 while TNMP added $0.19, as we're seeing the benefit of the third quarter from those companies and the first 24 days in the second quarter. Year-over-year, First Choice is down 7 million in margin, primarily due to the decreased number of customers which is partially offset by lower operating costs and better customer collections.

Again TNMP earnings were affected by its Texas rate reduction of $7.6 million during the year, offset by better operating expenses, a warmer 2005, and customer growth. PNM Retail added $0.14 to earnings. On the electric side, load growth of 2.6% for the year weather-adjusted contributed $0.11. Another $0.03 is related to warmer weather as we experienced an 18% increase in cooling days for the year.

$0.06 of the contribution to EPS is related to the residential gas rate increase, the impact from the first quarter. If you remember, the residential rate increase began in April of 2004. Another $0.02 is contributed to customer growth on the gas side. Those gains were offset by warmer weather in the first quarter and reduced off-system transportation.

Again, turning to the negative aspects to earnings, a big driver this year was plant outages. Plant availability for the year has cost us $0.15. Although this year's San Juan plant performance has been very good with an equivalent availability of 88.6%, it is lower than last year's record of 90.5%. So, San Juan cost us $11 million during the period. However, if you remember, we moved an average from the fourth quarter into the second quarter, so we expect to recover almost half of that through the rest of the year. Palo Verde cost us $5.9 million in outages. Four Corners for the year has run better and contributed $3.6 million.

Financing for the year cost us $0.14. It's related to the acquisition. $0.08 is related to the issuance of the equity-linked securities and increased commercial paper borrowing. $0.06 are the effect of dilution from the additional shares related to the acquisition. Purchased power, as you can see, was worth $0.12. $0.07 related to increased prices while $0.05 is related to volume. As Jeff mentioned, the average purchased power contract cost of our major long-term contracts increased 16.9%.

Depreciation increased $0.11. This resulted again from the $125 million of increased assets added to the Company. In “Other”, again, the $0.06 -- the expiration of the Navy contract, $0.03 for the year, and another $0.03, as I mentioned, with the Wood River investment reserve.

Turning to slide 10, we will go through margin by platform for the third quarter. This is the second quarter that we are using our new segment reporting model. As you may remember, our reporting is split between regulated and unregulated operations. Under regulated is PNM Electric, which includes retail electric and transmission, PNM Gas and TNMP in Texas and New Mexico combined. Unregulated operations are made up of PNM Wholesale, long-term and short-term, and First Choice Power.

We will start with overall margin which was up $74.3 million, or 46%. And that is really the result of having TNMP and First Choice in for a full quarter. As you can see, PNM electric and gas were essentially flat quarter-over-quarter. On the electric side, load growth and an increased number of cooling degree days were offset by the rate reduction and higher purchased power costs. On the gas side, margin was down just a bit as customer growth offset a reduction in off-system transportation. Again, TNMP contributed $45.7 million, down from 48.8 million in 2004.

Under the unregulated operations, long-term margin from PNM Wholesale was up slightly quarter-over-quarter with a small increase of $700,000. In the short-term wholesale operations, we had less excess generation due to plant outages and increased purchased power costs, resulting in reduced margin of $6.8 million. Again, First Choice margin added $34.7 million for the quarter. This is slightly down from $35.4 million in the third quarter of 2004.

If we turn to slide 11, we'll look through the margin on a year-to-date basis. Overall margin year-to-date is up $91 million, again due to the additions of TNMP and First Choice. PNM Electric was down $4.3 million due to plant outages and higher natural gas and purchased power costs. PNM Gas was up $3.7 million, reflecting the residential gas rate increase that went into effect in April of 2004, partially offset by the reduction of 190 heating degree days during the first quarter of this year. Long-term wholesale margin remained flat. Short-term wholesale margin decreased as a result of less excess generation available and increased purchased power costs.

On slide 12 we will go through the earnings per share for the third quarter by segment. As you see, we moved from $0.46 versus last year's of $0.45. Electric utility earnings on the PNM side were down $0.12 to $0.25. Load growth and weather contributed $0.09, which was offset by $0.07 of increased purchased power costs, $0.025 cents of plant availability, and $0.04 each of depreciation and dilution from the additional shares. We saw a 2.3% customer growth on the gas side which was offset by a reduction in off-system transportation, and earnings were reduced by $0.01 for depreciation and $0.02 for O&M.

TNMP and First Choice combined added $0.35. TNMP ongoing EPS added $0.14 to the third quarter 2005. This includes the $6.8 million impact for the quarter for the $13 million rate reduction in Texas implemented in May, which was partially offset by warmer weather, a 14.8% increase in cooling degree days.

If you want to compare last year's quarterly results for TNMP, ongoing EPS were $0.18 calculated on PNM Resources diluted shares. Half this decrease is attributed to dilution.

Wholesale operations reduction is primarily driven by a $6.8 million decrease in short-term margins. EPS was reduced $0.09. About $0.05 is reduced plant availability, $0.02 is due to increased purchased power costs, and we have $0.01 each for dilution and depreciation.

Despite the attrition of price-to-beat customers, First Choice Power's net earnings remained flat due to increases in commercial customers, mark-to-market gains and reduced administrative costs. First Choice contributed $0.21 for the quarter. This reflects First Choice Power's management of costs leading to the future plans for increased marketing activities to reduce customer attrition and add new customers. Again, if you're wanting to compare to last year, First Choice Power's ongoing EPS was $0.24 for Q3 2004, calculated based upon PNMR's diluted shares. Corporate and other costs resulted in $0.06 reduction in EPS mainly due to the acquisition financing charges and the Wood River investment reserve.

Turning to slide 13, you can see that year-to-date PNM Electric is down about $0.16, or 22%. Load growth and weather contributed $0.13 upwardly, offset by $0.10 of purchased power costs, $0.08 of plant availability, $0.06 of depreciation, and $0.04 dilution from the additional shares. PNM Gas had flat results year-over-year. That is the $6.7 million of residential rate increase that was not in effect for the first three months of last year and 2.2% customer growth, offset by warmer weather, reduced off-system transportation and increased depreciation. TNMP added $0.19. Their comparative net income year-over-year was up $500,000.

First Choice added $0.28 to the year so far, although it was down $7 million in earnings for the year. PNM Wholesale was down $0.13, again, due to plant availability, higher purchased power costs and increased costs to meet our customer load. We also saw some increases in depreciation and interest expense, and dilution from additional shares.

Corporate and other was down $0.15, as we previously discussed, mainly driven by acquisition financing $0.08, depreciation and dilution $0.03, and with the Wood River investment reserve. Overall, we are at $1.16 year-to-date compared to $1.13 a year ago.

And on slide 14, earnings guidance for the remaining part of the year. If you remember, in July we updated our 2005 ongoing earnings guidance, and today we are narrowing that range. The Company expects 2005 ongoing earnings per share to be between $1.55 and $1.65. The top-end of the range has been reduced because of issues of plant availability and higher purchased power costs. Even though performance in the third quarter was below expectations, we believe we can be within the revised range with good plant performance for the remaining part of the year, normal weather, positive results in ERCOT capacity auctions, and PUCT approval of First Choice's price-to-beat filing, and continued strong customer growth and maintaining our customer retention percentages.

And with that, I'll turn it back to Jeff.

Thanks, Terry. I've got nothing else to add. I would be happy to take any questions that you may have. Operator, if we can turn to questions.

(OPERATOR INSTRUCTIONS). Steven Rountos, Talon Capital.

A quick question, a couple of quick questions. The first one was on the purchased power costs for the quarter of $0.09. How much of that related to the power plant outages and how much of it was just increased purchased power costs given higher prices in the Southwest?

$0.05 was due to higher prices and then about $0.04 was to serve additional load growth from the customer side for the retail.

That was Tom Sategna, our Controller, so you know.

On then on the First Choice slide, when you talk about the hedging that you have done through Q1 '06 -- I think at the analyst meeting you mentioned that at First Choice you generally hedge a month in advance. Are these hedges newly put on? Over what timeframe were you putting these hedges on?

The notion of hedging only a month in advance, that was the old practice that was done by the prior management. We do things a little differently. And we are hedged forward -- it depends on what is going on within the marketplace. At this stage we're basically over 90% hedged through the first quarter and we have some hedges in place moving into the second quarter. We don't hedge too far out in advance because frankly, we think that the market prices today are going to probably on the longer-term move down a bit more. But -- and the load profile -- there's just not enough of an advantage to hedge too far out. But that is a change in the practice that was used previously to our acquiring First Choice Power versus what the approach that Jeff and his team is using now.

Got it. So, since you acquired it you've been hedging things out for a little longer-term?

Yes.

On First Choice itself, I know that gross margin was down 2%, which seemed to be a pretty impressive result given the customer attrition, revenues were down, megawatt hours were down and your price-to-beat was set pretty far below the cost of gas in your region over the quarter. Is all the differential there the hedging? I mean, how should we think about that?

That's part of it. Hedging is one piece. Certainly another piece is we have run in a little different approach to cost control. We have got a major effort which we are not yet ready to talk about that will change substantively the overhead costs associated with customer management. So, there's a number of things. I can't point to one.

I would also note that one of the things that Terry talked about was the change in customers and the margin impact due to reduced numbers of customers. A big chunk of those reduced customers from a margin side were these aggregated municipalities which effectively were lost in February, I believe it was February. It might have been early March before we were able to get our hands on that business. And that's an unfortunate loss because I think those were profitable customers for First Choice Power. But we have done, I think, a pretty good job of trying to make up for that. But it's going to take a little while for the marketing programs to kick in.

Is it safe to assume that your hedges, both the ones you had for this previous quarter and the ones going through Q1 '06, will be below the price-to-beat?

I'm not going to answer your question directly for reasons that I'm sure you can understand. We believe that the price-to-beat that we filed at the State is the appropriate price-to-beat, and we are in this to make money and we believe we will. So, I will let you read between the lines.

I guess really quickly the last question here. Can you break out the megawatt hours for the price-to-beat customers?

I believe -- is that attached in part of what we sent out? I believe if you look at the statistic report which is unaudited that was attached to the press release, if you look at the last page you will see residential mass-market, mid-market, but we don't show it broken out between our price-to-beat customers and our other customers. That is not a breakout we've typically provided. And I guess I'm not going to provide it at this time. We'll take your question under advisement and think about whether it's something we should provide.

Steve Fleishman, Merrill Lynch.

Jeff, with respect to some of the issues on purchased power and the like, if you had normal weather conditions in load and normal plant performance, and just kind of specified the issue here then of we had continued high gas prices, how much is just gas prices on their own a potential issue, gas and purchased power, I guess, setting aside those other things?

The purchased power -- there is -- I believe it's about a little over half of the purchased power is caused by having to buy more because of performance. The other half is because what we bought was more expensive, and it was more expensive largely because of natural gas prices as well as the unavailability (multiple speakers) of gas generation because of the rail problem. So, it's about half and half.

Let me rephrase the question as kind of a thought. When I look out and forecast, I'll assume normal plant operations and normal weather. It's hard to know what normal gas prices are. But if I look out let's say to next year and think about what does it mean if we stay with high gas prices, does that remain a risk issue to your portfolio, so to speak, if there is normal weather and normal plant operations?

In terms of the purchased power side or the natural gas prices?

Right.

Yes, it does. Also because in June or so we expect to have the Luna facility operating, which is, obviously, natural gas-fired. So, our exposure on the natural gas side will be increasing, although this transaction that we are inking today with APS certainly covers that natural gas risk. As you know, Steve, most of our wholesale contracts are either fixed price or they are fixed with a small amount of float. This is the first contract we have entered into that virtually the energy price is all float, based on what the index gas price is. So, it obviously is -- serves as a hedge on natural gas pricing.

My other question would be could you explain a little bit this -- you made this comment that you buy a lot of power from Xxcel, and they had, I guess, less to sell and they weren't running the coal as much. Is that an actual contract relationship or do you actually just buy a lot of their excess power at normal course?

No, they're contract relationships. We have got about 250 megawatts of longer-term contract purchases from Xcel, plus another 50 megawatts from Tri-state that is a term contract, meaning -- I think on that contract there is another three or four years left. So, they're all term contracts. On the Xcel contracts, they actually do have a fuel clause. So, when they were not able to use their coal units as much and gas prices went up, that flowed through.

Now, there's another issue which has been the basis for us filing a complaint at the FERC which goes to the basis of the calculation of how they do the calculation of the fuel clause. And it really goes to the question of when they make off-system sales, what fuel cost do they associate with those off-system sales. The complaint that we have filed has two components to it. One is a prior-period component, in which I think we allege that there's $33 million of overcharge. And then there is a separate complaint, which was really filed by some other customers and we intervened and joined in the complaint, that deals with how is it treated going forward. Because we continue to buy power under these contracts from Xcel. So, we will have to see how those get resolved. But we don't believe that it's being accounted for appropriately.

Lasan Johong, RBC Capital Markets.

I wanted to ask you a few questions on the APS contract. Is it my understanding that the contract is structured such that PNM has the ability to service that from either the new Luna facility or from purchased power?

We can serve it from any source we want to.

I see. So, that means that you're unrestricted whether it comes from Palo Verde, Four Corners -- anywhere else?

That's correct.

Can you comment again a little bit on the outages? Is there anything that PNM can do or is doing to fix the problems at Palo Verde?

Sure, Lasan. Is there anything that we can do directly? No, we don't operate the plant. But I have had a series of discussions with Bill Post . I will be over visiting with him and his revised nuclear power team. I have a lot of confidence in Bill and in Jim Levine. I think quite frankly that there's been a little bit of taking the eye off the ball. You have got a power plant that has been, really, the best or one of the best in the nation for 10 years. And I think that anytime that occurs, there is a natural tendency to start to feel like things will always be that way. And along comes some bumps, and they don't. They're not that way. And I'm not yet comfortable with the kind of response that we have seen through the course of this year. But I do have confidence in the commitment of Bill and Jim do not just pay attention to this, but to really make the changes and the differences.

For example, Jim Levine is now back out at the plant four days a week. He has been in APS' corporate office in downtown Phoenix for the last couple of years. So, he will personally be back on the plant site. That has a significant impact. They have brought in a new individual -- as I mentioned, I think, at our analyst meeting -- Cliff Eubanks, who was the plant manager at Arkansas Nuclear One with the energy system, who has got a very good reputation. And he has taken over as Vice President of Operations for the plant. And he brings a wealth of not only experience, but also when you come from a different plant and a different facility that's got common characteristics, there will be differences in your approach. And so, he will question things in a different way. He will think a little differently. That is good, in my opinion. Having everybody that always did nothing but grow up with a facility, you can get into the rut of group-think. And it's useful to have someone that will kind of stir it up and think a little differently occasionally. I think we're certainly seeing that in our First Choice operation. I think we're seeing that with Doug Hobbs in our T&D operation within PNM. And they're going to see it with Cliff Eubanks out at Palo Verde. So, I think they're doing the right things to help turn it around, and we are going to be their best partner in helping that effort succeed.

Is there a mechanism in which the other owners can get together and remove the operator or replace the operator part of the agreement?

There are provisions within the agreement in which things like that can be done. I am certainly not at a point of believing that is the right thing to do. As I said, I have confidence in Bill and Jim. And as long as they are responsive and as long as we believe that they are continuing to really focus on the things that need to change, they are going to have my support.

When would you withdraw that support?

I will tell you when we get to that point.

Paul Fremont, Jefferies.

Really two questions. One, the revised guidance range. I assume that fully takes into consideration the Palo Verde outages last week based on the emergency core cooling system.

Yes, it does, Paul.

Can you tell us a little bit more about what future action, if any, is expected to be taken? I guess there were recalculations, so at least it's, obviously, safe to operate. But is there any modification to the emergency cooling system that needs to take place in the future? And is there any type of increased oversight associated with that problem?

I'm going to ask Hugh Smith who heads our Generation and Wholesale business to respond to that.

At this point in time they are not expecting to have to make any changes. They are in an evaluation stage. They believe the system is being operated in a safe manner and adequate manner. They plan to evaluate whether or not any permanent adjustments in the system, or basically fixes to that valving system would be appropriate on a going-forward basis, but have no timeframe in which that is necessary to complete.

The question that was raised by the NRC staff that led to this situation has got an assigned probability of somewhere around 10 to the minus 7. So, it's a very low probability. But, obviously, when you're dealing with nuclear operations, you have to have responses for those. And the NRC was comfortable with the manual or the operator intervention procedure which Pinnacle or APS has put in place at this time.

Maurice May, Power Insights.

I want to start on First Choice, because the performance of that segment did hold up well in this quarter. I was just wondering whether you could give us any insight into the full-year profitability of this segment. For example, maybe some comments on the seasonality of that $14 million in earnings that it earned in the third quarter.

I'm going to ask Jeff Shorter to do that. Obviously, at this stage we do not break out our forecasted earnings by segment. We give it at a total corporate level. But if there are some general comments on seasonality trends or things of that nature -- Jeff?

Sure, good morning. First Choice, with our customers, we're predominantly -- the majority of our load happens in the third quarter. As you look out for the balance of the year, most of our load being residential tends to drop off fairly significantly if you look at -- for the fourth quarter. For us to be able to project on a quarterly basis, we don't currently do that. But if you think about our customer base being predominantly residential and some small businesses, that load profile tends to drop off from a megawatt usage as we get to the fourth quarter.

Well, the third quarter was off a wee bit from last year's third quarter. Is this an implication that First Choice for the full year might be off just a wee bit from the $30.5 million you earned last year?

Let me throw a couple of comments in there. There's a number of things that affect that. Certainly, in the fourth quarter last year we had that aggregated municipal load which we no longer have; it was lost in the first quarter last year. So, that is a change. On the other hand, you have got offsets. For example, I talked about the capacity auction participation. And I'll just say that it was a successful capacity auction participation, which they have never participated in. So, I think, Maury, I certainly understand where you're trying to go. I think there are a number of other missing pieces as we change how First Choice operates that make it a little harder to make that kind of a summary conclusion.

So, for example, it may be true that the baseline margin made from retail customers of First Choice may be less than it was fourth quarter last year. Remember that our strategy of acquiring this business was never solely to be in the retail business. It was -- it's because of our approach to markets where we believe we should first have load and then focus on resources, as opposed to doing it the other way around. And so, you will start to see us do other things with that business that will, at least we believe and our intent is, improve the profitability of the overall business. I know that's a little bit of a dodge of what you would like to see as an answer.

Moving on to my second question. Just as far as long-term strategy and regulatory perspective is concerned, does this third quarter, where you have frozen rates and you have plant availability down and you have replacement power costs up, does this give you pause to reconsider going forward using frozen utility rates for the New Mexico operation?

We have always had that pause as we look forward to 2008, because we have known independent of what has happened on the volatility in natural gas prices that we would move in the '07/'08 period into having a higher level of natural gas in our fuel mix. We are very, very low today. We are, I think, 2 or 3% of natural gas. And we are going to move to 5, 6, 7%. And as we make that move, obviously, it's of a higher cost and it has more volatility to it. So, we have made no decisions about what we will file in '07 for what our rate structure is going forward. But obviously, the volatility of natural gas prices and purchased power costs will factor into that decision.

David Grumhaus, Copia Capital.

I just want to go back to the question on the price-to-beat customer loss in the quarter versus the non-price-to-beat customer gain. Given where gas prices are versus where the price-to-beats were set in the various markets, I guess I would not have expected to see either the attrition or the growth in the non-price-to-beat customers. Is that really just a lag effect or are people -- you and others -- using pre-hedged power to go out and acquire customers?

This is Jeff shorter. We didn't have -- the prior management of First Choice didn't have any long-term hedges that otherwise would have allowed First Choice to effectively subsidize open-market power purchases for purposes of giving those to our retail -- that power price to our retail customers. Given the fact of where price-to-beat was for First Choice and the other AREPs price-to-beat levels where they struck, we had some fairly strong success in acquiring competitive customers, which if you think about it, if we're acquiring competitive customers they're either coming from someone else's price-to-beat or they are switching from an already competitive supplier. And with our price-to-beat customers, we have been able to maintain a fairly effective attrition rate, certainly compared to some of the other affiliated REPs in the market.

If your price-to-beat is a couple of dollars below where gas prices are, how are guys picking your customers off, or did more of this happen at the beginning of the quarter or light at the end of the quarter?

It's more at the beginning of the quarter, before you saw the absolute structural price shift up. Okay,

Okay. So presumably --

Typically, what we have found is on price-to-beat and price-to-beat strikes, we have found that we suffer more attrition not from just absolute price raises, but from competitive marketing programs.

And they're offering things other than price?

You know, I can't comment as to what all things are embedded into their offerings.

That's helpful. Any updates on the Constellation contract?

When we first took over the management of First Choice, one of the things we did was to sit down with the Constellation management team. And what we have been able to do with them is forge a much stronger business relationship. I know there had been commentary in the past around maybe termination around the Constellation agreement. However, I will tell you based on the folks that we have at First Choice being able to truly optimize the four corners of that contract and working with Constellation's team, we feel it is a win-win, market-sensitive contract, that we look to certainly use Constellation in the future. There is no current plan to terminate that contract.

Is it fair to say that it has been renegotiated?

There has been no renegotiations of the Constellation contract.

I think what we found is frankly, the operation under that contract was of a poor quality. And when we brought people in who knew how to actually use that contract, and in gaining not contractual changes but operating flexibility and how it is administered, we found them to be responsive. And I think -- I applaud Constellation for working with our folks to find ways to make that contract effective for both parties.

Last question. When will you give '06 guidance?

We will give '06 guidance in December. When in December I can't quite tell you. We haven't gotten quite that far. But it will be in December, before the start of the year.

Due to time constraints we have time for one more question from the line of Brooke Glenn-Mullin, JP Morgan.

I believe I heard Terry mention in the First Choice results that there were some mark-to-market gains. If you could quantify those, that would be great.

Brooke, I did not say there were any mark-to-market gains, but let us confirm if there might be some small amount embedded in there.

This is Tom Sategna. For the quarter, there was a mark-to-market gain for First Choice Power of about $800,000.

I would now like to turn the Q&A back to the management for closing remarks.

Well, let me just close. Thank you again very much. As I said at the start, we're not thrilled with the quarter. We know what the challenge is as we move through the fourth quarter and as we move into 2006, but I think, hopefully, we have been able to put some light on the notion of those things that are going well. And we know where the challenges are in terms of power plant performance and how we manage our purchased power costs, and the thing that we are all dealing with of natural gas price volatility. So, I am pleased with most of those parts of the operation. I look forward to seeing you all down in Florida, assuming that we have a hotel and lights and things of that nature. And if you would be interested in a private visit, I know we have got not very many but maybe a couple of slots that we can put folks in, so get hold of Lisa. Take care.

Ladies and gentlemen, this ends your presentation. You may now disconnect.