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TXU Corporation (TXU)

Q3 2006 Earnings Call

November 9, 2006 11:00 am ET

Executives:

Tim Hogan – Investor Relations

John Wilder – Chairman, Chief Executive Officer

David Campbell – Executive Vice President, Acting Chief Financial Officer

Mike Childers – Chief Executive Officer of Generation Development

Analysts:

Asha Arkon(?)

Craig Shere - Calyon Securities

Dan Eggers - Credit Suisse

Jonathan Arnold - Merrill Lynch

Greg Gordon - Smith Barney Citigroup

John Yurning(?)

Presentation

Operator

Good morning. My name is Tonesha and I will be your conference operator today. At this time, I would like to welcome everyone to TXU's Q3 earnings conference call. Operator Instructions. Thank you. Mr. Hogan, you may begin your conference.

Tim Hogan – Investor Relations

Thank you Tonesha, and good morning, everyone. Thank you for joining us to discuss TXU's third quarter results. This morning, we plan to keep our prepared remarks short leaving ample time for questions while limiting the call to 45 minutes. If you do not already have a copy, the press release and financial statements are available on our website, txucorp.com, under Investor Resources. The slides for this call are also on the website and when we refer to slide numbers, it will be the number in the lower right hand corner of the slide. A replay of the call will be available on our website approximately two hours after we finish. It will also be available by telephone for one week at phone number 706-645-9291 with conference ID 6037396.

During this call, we will make forward-looking statements which are subject to various risks and uncertainties. Discussion of factors that could cause actual results to differ materially from management's projections, forecasts, estimates and expectations are contained in the Company's SEC filings. I encourage you to read them. Our slide presentation and discussion of this call may include certain non-GAAP financial measures. For such measures, a reconciliation of those measures to the most directly comparable GAAP measures is available on our website under Investor Resources in the presentation slides for this call. With me today are John Wilder, Chairman and CEO, David Campbell, Executive Vice President and Acting CFO, and a number of other senior executives to assist with questions as needed. With that, I'll turn the call over to John Wilder.

John Wilder – Chairman, Chief Executive Officer

Thanks, Tim. Hello, everyone. Thanks for joining us today to discuss TXU's Q3 operational and financial results. I'll cover the quarter's operating highlights and David Campbell will provide details on the quarter's financial results. We'll close by opening the call to your questions. As you'll see from the attached slides, we had a solid quarter results with growth in earnings and cash flows that largely matched our expectations. I'm particularly proud of TXU Power, our generation business, which continues to set records while operating safely. Our Comanche Peak nuclear plant has set a quarterly and YTD production record. Our lignite units set a quarterly production record in Q3 and set a YTD production record as well. More importantly, both nuclear and lignite continue to operate at top decile safety levels.

Overall, we're very proud of the ongoing progress that Mike Green and his team have achieved in the Generation business. Their execution track record is a live demonstration of what we're striving to achieve as a high performing industrial company. As the leading power company in Texas, we're also committed to improving the infrastructure of the state's electric grid. We know how important it is to ensure that our customers have access to reliable, diverse and low-cost supplies, both today and in the future.

Slide six highlights our commitment to reinvesting our earnings in Texas. From 2001 to 2005, TXU invested 110% of its operational earnings in the capital base. As our earnings have increased over the past two years, we have maintained that level of investment. Over the next five years, we are planning to increase our reinvestment rate even further to 135%. From 2006 to 2010, we plan to invest more than $17 billion, making us one of the state's largest investors. Slides seven and eight show the economic impact of this investment. TXU alone will invest more than three times what the recent annual average of the entire chemical and the entire semiconductor sector have invested in Texas. In fact, considering only the impact of the 11 planned generation units, which is under two thirds of our total planned investment, and independent comments estimated that TXU will add 50,000 temporary jobs and 14,000 permanent jobs to the state economy.

In total, we will add approximately $26 billion to the gross state product. We are committed to ensuring that our customers have a safe, reliable electric system. This is the number one objective by a wide margin that customers emphasize in surveys about electric power. While our Generation business focuses on superior execution and driving this investment program, our retail business is also investing in the future.

On January 1st, 2007, the Texas retail market will make the transition to full competition. We are acutely aware of what has happened to most other former monopolies in deregulated markets. They typically struggle to adapt to the demands of competition. In particular, the need to innovate, develop new products and deliver superior customer service. Jim Burke and his team recognize this challenge and are doing all they can to overcome it. They are focused on two parallel initiates. The first is to establish TXU as the most innovative retailer in the Texas power market offering our customers the broadest set of choices and products. The second is to drive a broad set of customer service improvements, an area we know we need to continue raising our gain.

Slide nine and ten highlight some of the progress we are making in producing products with innovative features. With our new Pick Your Plan program, we offer the broadest set of customer products of any retailer in the market. We're providing customers options to choose green products, time of use products, market index products, near term discounts, long-term price protection or some mix of these features. For those who elect to stay on the monthly price to beat or related products, we've offered three years of price protection. This responds directly to customer feedback we've received in the polling that we've conducted.

Shown on slide 10, in a recent survey customers favored three years of price protection relative to a 10% discount with future prices indexed to natural gas by more than a two to one margin. For those seeking discounts as their top priority, TXU has also established itself as a leader in Texas. TXU provides 10 of the 11 lowest priced products that incumbents offer in their home territory. All the other incumbents in the state combined have just one product on the low price list. In addition, TXU has voluntarily extended the 10% discount for low-income customers through September 1st of next year. No other service provider provides the low-income discount which TXU launched in early 2006 and will keep in place through next summer.

Superior service will also be critical to surviving in a competitive market. Service is an area where you can never stop improving and there's certainly more we can do. Slide 12 highlights the progress we have made over the past couple of years. Since 2003, our average call answer time has dropped from nearly 5 minutes to nearly 10 seconds. The number of customer issues that require resolution have dropped by nearly 30%. The time it takes to navigate through our integrate voice response system has dropped nearly 30% as well. We track dozens of customer service metrics. All of them matter.

Continuing to improve is absolutely critical to Jim and his team as we make the transition to full competition. Product innovation and better service have contributed to better customer retention rates as shown at the bottom right of slide 12. During Q3 and first nine months of 2006, our residential churn rate has dropped by 18% and 26%, respectively. Of course, these efforts do not come without cost. As we discussed at the EI conference, our pricing and marketing actions in the retail business have impacted our 2007 outlook due largely to recent changes in commodity prices. But we believe that the effort is worth it and it will help us to establish a business that delivers net margins in a sustainable 5 to 10% margin range over the long term.

These margins are consistent with what retailers are able to achieve in other industries. Many achieve higher margins and none face the wholesale price fluctuations of electric power which is one of the most volatile commodities in the world.

In summary, we feel that we had a solid quarter. Our Generation business continues to execute well, demonstrating a track record of execution that should serve as a great foundation for the new plants we are building. Our retail business, while facing some challenges, continues to innovate and improve its service levels recognizing that full competition will require excellence in both areas. Finally, we continue to reinvest over 135% of our earnings in new energy infrastructure to power the future of our customers. I'll now turn the discussion over to David Campbell.

David Campbell – Executive Vice President, Acting Chief Financial Officer

Thanks, John, and good morning to everyone on the call. My comments will focus on the financial results for the quarter. Our third quarter reported earnings were $2.15 per share compared to $1.16 in 2005. YTD earnings were 4.43 per share compared to $1.76 last year. Special items in Q3 total a positive $0.01 with the benefit of anticipated insurance recoveries related to last year's securities lawsuit settlement partially offset by TXU Electric Delivery's transition expenses in preparation for closing the Infrastrux Energy Services joint venture. YTD special items also include a $0.27 charge from the impairment of our natural gas fire generation facilities, the net $0.09 effect of adjustments associated with the new Texas margin tax and a $0.15 per share charge associated with the day one book loss for a series of large natural gas hedge transactions, all reported last quarter. Except for the TXU Electric Delivery transition expenses, these special items are all non-cash.

As shown on slide 14, operational earnings for this quarter were $2.10 per share, a nearly 80% increase over Q3 last year. These results fall generally in line with our expectations, reflecting solid results overall and particularly strong performance in TXU Power, with mixed performance in other parts of our energy holdings segment. During our August earnings call, we estimated that Q3 would account for 60% of operational earnings for the remainder of the year. Relative to the midpoint of our outlook range, this would have implied $1.88 per share in the quarter.

Slide 15 details three factors that impacted results in Q3. Considering these factors, quarterly performance generally fell in line with our August estimate. First, unrealized cash flow, hedging effectiveness and mark to market gains associated with our long term hedging program equaled $0.26 per share. During the quarter, the forward value of our hedging program increased by approximately $800 million. Due to an increase in forward heat rates, a portion of this increase in hedge value has been recognized as ineffectiveness gains. In addition, significant volatility in commodity markets created inter-period losses in our wholesale business of $0.04 per share that will be offset in future periods.

Finally, the net effect of warmer weather and customer efficiencies led to slightly lower average customer use, resulting in an estimated loss of $0.01 per share. Netting out these various factors, results for the quarter would have been $0.01 higher than the implied August estimate. As John mentioned, operational performance in TXU's Generation fleet was particularly strong in the quarter. This was a factor in the significant increase in energy holdings contribution margin which was driven primarily by higher retail prices reflecting significant commodity price increases last year.

The core businesses also achieved ongoing cost productivity gains as shown on slide 16. Excluding incremental investments in TXU Development and TXU Construction, the corporate center and competitive businesses reduced operating and SG&A costs by 4% relative to last year. Overall, excluding the effect of reduced shares, net corporate expenses increased $0.05 from Q3 2005 driven by higher interest expenses. TXU Electric Delivery's operational earnings were $0.01 less in Q3 2005, $0.03 excluding the affect of reduced shares. This primarily reflects incremental expenses related to the city's rate settlement as well as increased interest expenses.

Higher revenues from warmer weather, growth and increased transmission revenues were substantially offset by lower average customer usage. On a consolidated basis relative to Q3 of last year, reduced shares outstanding improved operational earnings by $0.10 per share. We have repurchased nearly 19 million shares YTD and more than 30 million since October of 2005. We have approximately 3.4 million shares remaining under the 2006 program, the authorization for which has been extended through next year.

As announced earlier this week, the board has also authorized an additional 20 million share repurchase in 2007. TXU will apply its capital allocation philosophy in determining the timing and amount of these repurchases over the next 14 months.

Slide 17 highlights the Company's credit metrics which improved for the seventh consecutive quarter. Relative to last year, YTD operating cash flows increased 97% to $4 billion. These results include a net impact of cash flows relating to the Company's long-term corporate hedging program. From a trailing 12-month perspective, the interest coverage ratio has increased 39% to 6.4 times. The debt to EBITDA ratio declined 41% dropping from 3.4 to 2.0. For these metrics, we have also improved substantially in relation to other companies in the electric power sector as illustrated on slide 18. Based on our performance of the past 12 months, we are now in the top quartile for the industry for interest coverage, debt to EBITDA and debt to enterprise value.

The last topic I'll mention is our earnings outlook for the year. As we noted during the conference earlier this week, TXU Corp. is maintaining its outlook for operational earnings of $5.50 to $5.75 per share for 2006. This concludes our prepared remarks. We will now open the call to your questions.

Questions-and-Answer Session

Operator

Operator instructions. Your first question comes from the line of Asha Arkon(?).

Q - Asha Arkon(?)

Good morning. John, could you just, I guess it came on the wires that the regulated industry committees are going to meet today and you're going to be making some presentation on the retail markets. Could you just mention what the scope of this hearing is? It's just normal updates or what's the scope of these hearings, I guess, today?

A - John Wilder

It's just normal. Part of that hearing process is to discuss a variety of issues that the legislature will need to think about in its coming 2007 session. There's going to be a number of companies represented. We're going to be discussing the state of the market, both retail as well as wholesale, and talk broadly about what big public policy initiatives and issues need to be considered to make sure this market continues to be the best functioning market in the U.S. And that's kind of normal course of business for us to have prehearings before the session to help try to set the key issues, at least from the perspective of all the market. We're actually quite excited and encouraged about the hearing because we think there's some big issues that the state leaders need to think about, particularly these issues around reliability. It's surprising us all how quickly these reserve markets are melting away. We need to make sure there's very constructive laws and very constructive public policy to make sure that we're able to get these plants built on time.

Q - Asha Arkon(?)

If I can just have a follow-up, John. As I was looking through the slides, one major change that came in your presentation two days ago was the retail position previously, you had a, it was a perfect hedge, I guess, somewhat of a hedge. And now in the presentation, there's a range for each year, 2008, '09. And I just want to understand, how should we look at that range? I mean the range is pretty wide. How should we look at that range in terms of the retail position as an offset to the hedge?

A - John Wilder

Yes. I'll open with that, then I'm going to ask David to provide some more specific color. We've always, Asher, on our hedge tables as well as any sensitivities we've had, we've always had a range for retail, and we've always capped retail in our forward plan at varying levels. When we first started doing our plan, we used gross margin, so we would cap it at $30 or so. Then we started using that margin and we capped it at 5 to 10. Sometimes in which we gave a forward view where we ran our forward plan, we ran into the cap, and other times we didn't. The majority of the plans, at least as I can recall, we've actually invoked that cap. The only time we weren't required to invoke that cap was the last forward business plan that we'd calculated because the underlying wholesale commodity prices were high enough that that never needed to be operationalized. So what we did is we saw the wholesale prices come down again. That was unexpected to us, as well as unexpected to many of the market followers, as we started introducing a feathering down of what we call our hedge effectiveness. If you look at it now, it's about 90%. At least in the current year, it's about 90%. In our forward view, we kind of walked that thing down to a 50% effectiveness level by, as you noted, widening out the range. So I'm going to ask David to kind of give you the mechanics of it but that's our thought process behind it. Our thought process is retail is a margin business within a certain expected margin range. Any time you get materially outside of that range, we would expect to see those benefits of continuing to flow to the customer. It's going to have a wider range around it as this market unfolds. Someday when it's fully competitive, our retail business would be just a pure, pure, very narrow margin range. Right now, we think it needs to stay pretty wide in five to ten, mainly driven by the volatility of the underlying power prices.

A - David Campbell

All I'd add, this is David Campbell. When we think about our forward natural gas sensitivity, we factor in our base load position, retail, with an estimate around what the range may be in the future. We also factor in our natural gas forward sales. As you know, we've got 1.5 billion sold forward natural gas hedge position so that's a very important part of our overall hedge portfolio. When we gave our sense for 2011, indicative range for the growth rates between now and 2011, you saw that we estimated our exposure to natural gas in 2011. When we did that, we used the midpoint of the range that you saw for retail, is our best sense of what that sensitivity would be to natural gas. When we think about it, when we try to compile that into a point estimate, we use the midpoint of that range, and it reflects, as John noted, that over time, we've always in our forward plan assumed that the net margins for retail will be in a sustainable margin, and that relates to wholesale power prices. I think that's the way we expect the competitive market will unfold.

Operator

Your next question is from the line of Craig Shere.

Q - Craig Shere - Caylon Securities

Three hopefully really quick questions. Any updates on the Sandhu coal plant development plans? Second, in the fuel cost increases you all noted with the adjusted guidance, 2007 through the end of the decade, is most of that in uranium? Because coal costs seem to be moderating a bit and other companies seem to be suggesting a reversal of some of the costs for coal. And the final question, how are you all accounting for some of the one-time credits you're giving to retail customers? I think our, Reliant took a one-time charge this quarter. I'm just trying to figure out how this is going to flow through over time as you give people incentives to stay with you.

A - John Wilder

Craig, I'll knock out the first two and David will mop up the third one. Our Sandau project is progressing very well. When we entered that project, we had a permit that was characterized as less than perfect. It was a permit that had been developed by our partner as well as another co-developer. We have since worked very constructively with the government to try to perfect that permit, and we are highly confident that we're going to be able to work through those details with the government between now and the end of the year. Our cost that we described as mainly rail and uranium, we see broadly a softening of the commodity of PRB, not a lot, but broadly a softening. Now it's taken a pretty big reduction over the last six months. So as we think out long term over the future and that's all we try to represent in our forward view, is we think long-term over the future delivered PRB coal will have some upward pressure on it as a result of the transportation charge, and we also anticipate some upward pressure on nuclear fuel, mainly as a result of the uranium commodity.

Q - Craig Shere - Caylon Securities

Would you advise us to model Sandau more for 2010 or '11 instead of '09 at this point?

A - John Wilder

No.

Q - Craig Shere - Caylon Securities

Okay.

A - David Campbell

On your third question on retail plans, we have announced that we're going to give customers a one-time appreciation bonus of $100. That will go to each TXU residential customer that lives in areas where we offer the price rate as of October 31st of 2006. So it will be a special charge in Q4 given the timing of that bonus. That will be we estimate about $165 million pre-tax. Any other expenses that we incur for the Pick Your Plan options or otherwise will flow through operational earnings as they typically would.

Q - Craig Shere - Caylon Securities

So when we hear the Q4 call, we should keep in mind then the 165 kind of as moving money between quarters, because your future quarters thereafter will be a little higher than they would have been otherwise, is that fair?

A - David Campbell

I think the right way to look at it is an obligation that we incur on a fixed basis as of the end of October so really it is a special charge in Q4. The cash will flow out later. But it is an obligation that we incur. It's for all customers, residential customers, as of October 31st.

Operator

Your next question is from the line of Dan Eggers.

Q - Dan Eggers - Credit Suisse

On the Texas construction program, can you just give us an update on how much of that cost has been secured? It looks like you guys locked in some more in the quarter and I just wondered if you could give us some color on how much the $1,100 is looking pinned down at this point.

A - John Wilder

We're over halfway through with our opening book process, with the reference plant program. That process is yielding about target results. We've had some equipment a little cheaper, some equipment a little more expensive, but on balance, it's delivering where we expected it to. Sandau came in right on top of the numbers, 1100 KW, technology adjusted, so we've got that one buttoned down. And Oak Grove is coming in real nicely as well. So we like the progress we're making. We've had to pay a little bit more for steel than we thought we would. So we wiggled around and knocked that cost down by global sourcing. One thing we found, Dan, is we only have, we think we're going to end up with about 30% low cost country content in this buildout program. That's one key part of our learnings is to try to raise that percentage as much as we can. If we're able to get that up to about 80% or so, we think we can continue to make some fairly substantial progress in the amount of capital that needs to be invested in these generation facilities. So far so good. But it's a day-to-day piece of work that we've got with our contractors. We've got literally hundreds of RFQs out in the market for a wide variety of balance and plant equipment. We're working on detailed labor studies of what we think the labor market will produce. And continuing to work with all of the fuel oriented suppliers, both the commodity co as well as the transport suppliers to get a good type range for what the delivered fuel costs might be.

Q - Dan Eggers - Credit Suisse

Okay. I guess you obviously are going to hold back a little bit on the expansion program until you get some of these contracts in place like you discussed this week. But I was wondering if just by order of magnitude if you could get some color of what you're expecting cost per kilowatt construction to be as you think about moving into PJM and some of these one-off projects elsewhere in the country?

A - John Wilder

Yes, we've done a modest review, a modestly detailed review of these other markets. It's about 200 a KW premium. I'm going to ask Mike Childers to jump in and give you a little color around what drives that. Majority of it is the wet scrubber versus the dry scrubber. But there's also a little labor premium that we've built into our thinking and Mike can give you some more specifics, Dan.

A - Mike Childers

Yes, Dan, it's really, as John touched on, it's the cost of a wet scrubber versus a dry scrubber that we would use on the Texas plants with the PRB as well as there's a premium for labor productivity issue as well as a premium cost for labor as we move towards these. And they're really the only big drivers in the program. We're sticking with the standard web design and we believe we can continue to drive those costs down through foreign country source out.

Q - Dan Eggers - Credit Suisse

Got it. Now, just one more and it'll be quick. But on Oak Grove plan to saw down that equity interest, does that, does the money exchange hands when you guys, when that plant comes into service or does it happen in advance of the in-service date?

A - John Wilder

COD.

Operator

Your next question is from the line of Jonathan Arnold. Jonathan, your line is open.

Q - Jonathan Arnold - Merrill Lynch

Good morning, guys. Hi. Couple of quick questions. You said in the releases earlier this week that from Q4 you'd start to exclude mark to market and hedge ineffectiveness. Does that mean that the 2006 numbers will affect – you're saying you'll make your numbers excluding whatever gains you've had so far this year or are we really talking about 2007 for the change of basis?

A - John Wilder

Jonathan, David better answer that one. I've heard this explained. And just get ready. It is going to take a while.

A – Tim Hogan

Hey, Jonathan. This is Tim Hogan. We will adjust how we report the prior period numbers. When we start that such that we started the long-term hedge program in Q4 last year. And we will adjust numbers from Q4 of last year to what operational earnings under the same methodology. I think the majority of the analysts back those numbers out anyway. We don't include them in our forward outlook. So I think that will make everybody on basically the same basis, so it will create less confusion, some people backing the numbers out, some people not. We'll just present it that way.

A - David Campbell

Yes, we've included each quarter since we started the program, Jonathan, we've broken out what the impact is as the hedging effect in this gains or losses. There were losses in Q4 of last year and I believe in Q1 and then gains in the last two quarters. So rather than making you all do the backing out math, we're going to, going forward basis, we're going to make this change. But as Tim mentioned, we're using a consistent methodology in how we're thinking about it and reporting. In other words, we're not, this will more accurately reflect when the earnings are actually realized through the P&L as opposed to bringing them forward, either losses or gains, related to the ineffectiveness of the hedge.

Q - Jonathan Arnold - Merrill Lynch

Okay. And one other, which was you just mentioned this $200 a kilowatt premium on building plants outside of Texas. And can you just relate that to the statements you made about the target of 8 to 900 on using more low cost country sourcing? Is that, are you still planning to get to the 8 to 900 despite this premium or should we adjust that number up for the premium?

A - John Wilder

Jonathan, I think we, as we continue to drive down the costs associated, or increase the content of foreign country sourcing, we believe the 8 to $900 a KW is achievable. The $200 premium was associated with simply taking our reference plant and moving it toward the east. There are other markets, quite frankly, we don't think there'll be a premium associated with, over the Texas market, but as we move towards the PJM region and moving the reference plant we've designed today, that's the

$200 premium.

Operator

Your next question is from the line of Greg Gordon.

Q - Greg Gordon - Smith Barney Citigroup

I think I understand how you've changed your models in terms of functions for inabilities. I'm going to rephrase it for you and you tell me if I'm thinking about it correctly. Before, when you thought about retail, you thought about a 5 to 10% range in terms of sustainable debt margin cap depending on where wholesale prices were on the forward through. Now you're saying that you assume that hedge is only 50% effective. So wouldn't that, does that mean that you've essentially lowered the cap from 10% to something closer to in between the range in terms of where you think margins would sustain themselves out in a low commodity price environment?

A - John Wilder

Greg, David's going to answer that. But the short answer is no. The 5 to 10% assumption is identical to what we've used in the past. What we mean by the 50% effectiveness is how much retail business we have to offset our increasing long business. I mean, David can take you through the math. But think of it as our wholesale position is going to be growing over time, what we call our open position. And our offsetting positions, both our long-term PPAs as well as our retail business as well as our forward hedges, even if they might grow or just slightly decline in the case of retail, our open position through our new production from our new facilities will overwhelm the slight increases we might have in some of our more natural short positions. So that's how our effectiveness potential changes over a longer period of time. But it's best to get it mathematically. I'll ask David to provide that to you.

Q - Greg Gordon - Smith Barney Citigroup

I can get that offline. I don't want to take up too much time. So you're basically saying that the number of terawatt hours you're targeting to serve on retail hasn't changed but the number of terawatt hours you're producing wholesale has gone up such that the hedge is less effective?

A - John Wilder

You got it. Exactly.

Q - Greg Gordon - Smith Barney Citigroup

Great. My second question is looking at the customer usage numbers in Q3, on average, you're 11.2% down in usage. Weather was slightly warmer than normal. That's a huge number. I haven't seen customer price elasticity like that in a long time in the electric utility and pretty much anywhere. Can you give us some qualitative understanding of what types of conservation you're seeing by what types of customers? And does that change in any way your view on how much new supply is even in the state if we could see that type of demand response?

A - David Campbell

Greg, this is David. I'll answer initially just from a math perspective. I think you're looking at appendix table C for other listeners on the call. You'll see retail electricity sales lines and gigawatt hours, I'd call out two components to it. First, the native market residential usage is down 11.3%. A chunk of that, of course, is due to customer churn. So not all that total is related to usage. It's partly that we also have a smaller number of customers from last year. If you look in the bottom portion of that table, you'll see that residential average kilowatt hours per customer are down 4.7%. This is relative to last year. So last year was also a warmer than normal quarter. So relative to average usage that we would predict in our plan, we're about on. But given that while weather is about as warm as last year, you'd expect that we would have above average customer use. So we are seeing there some elasticity effects, our customer efficiency effects in the plan. We've embedded some expectation of demand response in our 2007 outlook as you saw from the table where we walked forward our previous estimates for 2007 versus our current. That was one of the factors that we included that led to a slight decline in our outlook range. It's hard to know what it will be on a sustained basis because it was such a warm quarter. So if it's normal weather, will we see the same level of sustained elasticity impacts? It's hard to know for sure. I think it's something that we're watching, continue to observe. If you look in our Electric Delivery segment which is another table further in the release, you'd see a decline in overall volumes as well relative to last year that's not as sharp. Typically the residential customers often have the most significant elasticity. So if the overall averages are not as sharply declining, there'll be less of an impact on the overall supply because, of course, industrial customers tend to be less elastic in that regard. Hope that makes sense but again culling out the different parts of the table it's probably more relevant to look at that 4.7% recognizing that last year was also quite warm.

A - John Wilder

And to answer the back end of your question, Greg, we've built the elasticity assumptions that David just described into our forward view of what demand will be. I mean it makes an impact. I think it's something like half a plant or something like that. It's not a lot. We've run our plants hard enough that that makes up almost a gig. So we've knocked a gig out of the equation just by higher operating performance. We're low to mid 90s in terms of availability so there's not much left there. We're working these demand-side management programs as hard as we can. We think that might knock off half a gig or something like that. And Tom and his business continue to work to try to innovate and improve line losses on transmission. That might knock out about a half a gig or so. You put that in the whole mix of things, and the state is still about 15 gigs or so short over a 10 or 15 year period of time or so. So it helps, but it's about a 5%. All of those factors I just described to you are about a 5% contribution to what we need to do to fill in the supply.

Q - Greg Gordon - Smith Barney Citigroup

Great. So the right answer is it's more like a fore handle but you really need to see sort of comparable quarter over quarter comparisons on normal weather to really clean up the data to know how much of that is really true conservation? Is that fair?

A - John Wilder

Exactly. What we don't know, it just takes a while to wade through the data and wade through the experiences. How much is behavioral and how much is structural? So how much is behavioral because we've worked really hard to put in the consciousness of the customer that there's going to be higher electricity prices, so we want them to be on guard and kind of thoughtful about their usage, and how much is structural by having a home envelope improved by better weatherizing or something like that. It's really, really difficult. We've got a number of neat products that we offer our customers on this, but it's pretty difficult to find many of these, particularly home-based products, that have paybacks any quicker than about five years. Most of the customers that we're interacting with, they think of that as being about the amount of time that they're going to own a home. So despite our strong encouragement, many just seem unwilling to invest in these five-plus year paybacks projects to lower their overall consumption.

Q - Greg Gordon - Smith Barney Citigroup

Great. But you have baked in sort of half a gig of that type of activity in your models? I just want to be clear that was one of the components of many things you baked in to your supply/demand balance?

A - John Wilder

Exactly. In fact, what we did is we first started with those three variables that I described to you. We said, okay, how do we attack this thing? Can we run our plants harder? Can we reduce line losses and can we reduce unit consumption? We spit out what impact that would have and we still ended up, over a 15 year or so period of time, 15 gigs short. So these other things matter. We're going to do them. We're not giving up on them, but you've got to answer this increased demand problem with the supply response to really make a meaningful impact in the prices in Texas.

Operator

Your next question is from the line of John Yurning(?).

Q - John Yurning(?)

Good morning. Two questions on retail. In the story board slides that you showed at EEI where you provided the new $7.55 to $7.85 2011 EPS outlook, what retail net margin is implied in the $7.55 low end and the $7.85 high end? Is it 5% on the low end and 10% on the high?

A - David Campbell

John, that range encapsulates all the factors that could be driving things down or up. So it's not mechanically just one element that leads you to the low end or the top end. In a declining price environment, generally we model at a 10% net margin cap, in that range. Point estimates always imperfect, of course, in how the market actually plays out. But given the declining price environment, we typically would model it with a 10% net margin cap. The range reflects sensitivities across a number of different factors.

Q - John Yurning(?)

Okay. Can you talk about what the perhaps the average 2007 to 2011 churn assumption is that's used in that 2011 outlook? Is that possible to give?

A - David Campbell

Yes, it's consistent with the churn estimate that we had for this year. So the overall gross churn rate off of the monthly rollover, the month to month customer, PTV rollover products of about 10% and the net churn in the 7 to 8% range.

A - John Wilder

And one point to add there, John, is what David just described was the churn in our incumbent markets. But we plan on offsetting that by customer acquisitions in other markets. So our broad market share, our long-term goal is to have our broad market share about what it is today.

A - David Campbell

Yes, our thinking is that over time the market share will stabilize. So we think that our churn rates should improve eventually over time as the deregulated incumbent. We recognize that we're the big target and we're going to continue to lose share for a couple of years. We do hope in the back end of the period, we'll be able to see retention levels that improve over the numbers I just gave you.

Q - John Yurning(?)

Okay, that's helpful. So basically the 7 to 8% net churn assumption doesn't capture what John just mentioned, which is the out of territory gains. And is it safe to say then that some out of territory gains to offset that are embedded in the new 2011 outlook?

A - John Wilder

Yes, absolutely.

Q - John Yurning(?)

Great. Thank you.

A - John Wilder

Thanks, John.

Tim Hogan

Thank you all for joining us today. If you have additional questions, please contact the IR team. We will be on the telephones all afternoon. Thank you, bye.

Operator

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