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TXU Corporation (TXU)

Q1 2006 Earnings Conference Call

August 1, 2006, 8:30 am ET

Executives

Tim Hogan - Director, Investor Relations

John Wilder - Chairman of the Board, President, Chief Executive Officer

Jonathan Siegler - Vice President, Strategy and Mergers & Acquisition

David Campbell - Acting Chief Financial Officer, EVP Corporate Planning, Strategy and Risk

Mike Childers - Chief Executive Officer, Generation Development, TXU Corp.

Analysts

Steve Fleishman - Merrill Lynch

Paul Paterson - (?)

Dan Eggers - Credit Suisse

Vic Khaitan - Deutsche Asset Management

Danielle - (?)

Ryan Orson - (?)

Terry Miller - (?)

Michael Lapides - Goldman Sachs

Presentation

Operator

Good morning, my name is Amanda and I will be your conference operator today. At this time, I would like to welcome everyone to the TXU Q2 Earnings Release Conference Call. [Operator Instructions]. Mr. Hogan, you may begin your conference.

Tim Hogan - Director, Investor Relations

Thank you, Amanda and good morning everyone. Thank you for joining us to discuss TXU's Q2 results. If you do not already have a copy, the Press Release and Financial Statements are available on our website, www.txucorp.com, under Investor Resources. The slides for this call are also on the website and when we refer to the slide numbers it will be the number on the lower right hand corner of the page. A replay of the call will be available on our website approximately two hours after we finish. It will also be available via telephone for one week, at phone numbers 706-645-9291, with conference ID 215 2137.

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 discussions on this call may include certain non-GAAP financial measures. For such measures, a reconciliation of those measures 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, Jonathan Siegler, Vice President, Strategy and Mergers & Acquisitions, and 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 of the Board, President, Chief Executive Officer

Good morning. We're happy to be with you today to brief you on TXU. I will cover the quarter’s operating highlights and discuss TXU Power Development Company. John Sieglar, will cover an important strategic --we have completed, and David Campbell will rap up with more detail on the quarter and our financial and risk management strategy.

As shown on slide IV, operational earnings per share increased to 104% relative to last year, or 78% excluding the impact of hedge ineffectiveness gains. Slide V through 8 highlight TXU’s operational performance. Our base load generation set a production record for the first half of the year, performed particularly well setting records in two consecutive quarters. TXU Electric Delivery continues to invest in system reliability improvements and technology upgrades. 161,000 automated meters are now deployed across the system with 370,000 target by year end. TXU Electric Delivery has also created an innovative joint venture, infrastructure energy services. The new venture will enable access to state-of-the-art equipment and an increasingly tight supply environment, best in class construction and maintenance capabilities and a wider labor pool for emergency response.

TXU wholesale and TXU energy also achieves solid results. TXU wholesale managed to a 10 day stretch of 100 degrees and a peak load that exceeds last year’s by 3.5%. This growth rate is equal to almost four of our planned new power generating units. TXU Energy continues to deliver innovative customer solutions offering nine of the 10 lowest priced products of any incumbent provider and its core market as shown on slide VII. These products are helping improve customer retention by higher bills to the commodity prices and hot weather. As shown on slide VIII in territory residential share improved 39% for the quarter compared to the same period of ‘05. Overall, it was a solid work.

Turning to our power generation program, we’ll discuss the topics listed on slide IX. I’ll begin with an overview and the first four. Slide X shows our progress today. Overall our cost and schedule matrix are on track relative to the estimates we gave you in our Q&A update, while the commodity market has improved slightly. While there has been no formal action taken on our permits, I’m confident that the process remains on track. We are working with the Texas Commission on Environmental Quality to establish emission limits using the best available control technology or BACT to protect the health and safety of the public. Each plan will achieve emission control limits that are essentially the same as those of two permits recently approved by the commission and all the new plants will use technologies that the commission determine and those cases constituted BACT. In addition, we are working with the commission to conform our commitment to offset 100% of key emissions for the new plants as well as an additional 20% reduction in key emissions.

We are confident our permit application and proposed emissions control technologies will be approved. In April, we establish a dedicated advocacy team under the very capable leadership of Mike McCall. Their efforts focus on influencing public opinion in the areas we will have standing in the permitting process. Support for our plan is very high and most rural communities near the plants with supporters outnumbering opponents four to one. One community even sponsored a petition and supported the project that was sign by nearly all of its residents. Statewide and in Dallas-Fort Worth area supporters outnumber opponents two to one. While a small number of Dallas and Waco officials and some media outlets have raised questions they are generally not calling for the permits to be denied, but instead are challenging the permitting process and technology choices around an entire group of proposed plants including TXUs. We will continue to help them understand the real energy challenges Texas faces and the need for new, secure and economic power generation.

We have made substantial progress in our engineering construction and startup efforts. As you know from our June 8 update, we hired Chuck Enze as CEO, TXU Generation Construction and tap our own Steve to lead the operational readiness and planning group. Chuck has over 30 years of experience in leading mega projects from concept to operations. He has quickly built a team of experienced project directors and construction managers with 200 years of relevant experience and delivery of over $50 billion of mega projects. They have already delivered substantial value by creating an increase competition to more aggressive engagement of the equipment and supply markets and eliminating work scope that doesn’t add value and initiating constructive relationships whether strategic EPC partners. Steve is one of our best engineering executives, he and his team are developing TXU’s multi-horizon generation technology plant, which I’ll mention later and making sure our new plants are ready to operate at the highest performance levels.

Chuck and Steve are working closely with our EPC partners to deliver against the variable from slide XI by leveraging these relationships in our existing sites and infrastructure we continue to be confident in our $1100/KW cost projection for our reference plants are eight standardized units compromise at $11,00/KW estimate. Since June 8 we have held 20 lean workout sessions to plan the TXU operating system to cut waste, improve cost, schedule and performance, and design a more competitive plant. As with our EPC partners we’ve engaged in a process with our potential suppliers to take advantage of efficiency of scale purchasing as slide 12 shows. Building up our success in purchasing eight boilers from BMW, we have finalized an agreement with GE to purchase eight steam turbines. That completes the foundation of our plant power plant. We believe the scale of our program and the lean processes will reduce the capital cost by 24% and the schedule by 32% compared to single plant developer. The team is finalizing commercial terms to acquire over 75,000 rail cards given its flexibility, pursue cost reductions and materials, and equipment and employ spotters on a just-in-time basis.

We are also nearing completion of processes to purchase our air quality control systems and acquired nearly 200,000 tons of structural steel necessary for our units. As summarized in slide 13, we completed agreements for nearly 40% of our requirements and are close to finalizing 50%. We’ve also issued initial request for cloths for another 25%. Our infrastructure planning for dual-rail connectivity at each side is progressing well. We are also in discussion with both major carriers for long run transportation of coal from the Power River basin and we’ll soon turn our attention to our coal supply strategy.

Overall, we are progressing very well in our power generation program. In light of the substantial reliability problems across the US, which have affected millions, we’ve been asked by many of our investors and the general public, how our power generation program will help solve energy, reliability, and price problems. Frankly, they have a reason to be concerned. According to the US Energy Information Administration or EIA, more than half the power generation capacity in US was in service prior to 1980 according to that period now they just cost US economy about a $100 billion per year. That’s 1% of GDP or roughly $0.50 for every dollar spent on electricity.

April predicts that the economic loss figure could rise to $300 billion per year unless substantial investments are made in our delivery systems and power supplies. Even Texas market that settled for 25 gigawatts new generation added in the last 10 years had a weather related surprise in April when the grid was cut short of supply. That rolling blackout the first in 17 years was a wake up call. In North Texas every minute of a blackout can cost a county up to $10 million. Over the next decades six million new residents are expected in Texas, increasing the demand for electricity to 0.1 and 2 gigawatts per year. With our new generation our cap forecast reserve margins will drop below reliable levels by 2008 and drop to 6.8% by 2010. Reliability is a very real problem and the cost will be substantial if we don’t fix it. Nationwide, demand for electricity is growing 1.6% annually.

EIA suggests over the next 20 years, 200 gigawatts of new capacity will be needed just to keep prices stable, much less provide price relief. Between 1995 and 2005 and with the 90% of US generation capacity, additions were gas fire, this shift is expected to increase natural gas imports by 400% for the next 15 years. The US which accounts for less than 5% of world gas reserves will continue to rely on nation’s located in less stable parts of the world. Natural gas prices are already almost four times higher today than they were in the 1990s and prices post 2010 are expected to remain more than three times as high. This reliance on natural gas will continue to make US industry less competitive and expose consumers to unacceptably high and volatile electricity prices

Faced with the reality of this highly uncertain environment we had to make a decision on the technology for our power generation program. We started by understanding what our customers want. As slide 14 reflects they rank reliability first and competitive prices second. We then spent a year evaluating generating technologies and our ability to meet those top two customer needs. Slide 15 summarizes our review. We determine that our noble energy must be for the solution Texas is now the number one wind generator nation and TXU is the states largest buyer. We would double our portfolio our renewable capacity by 2011 through our new company TXU renewed, unfortunately wind power does not have the capacity or performance characteristics to meet Texas power needs. During the summer when demand is highest the average wind generation is lowest, also 58% of the wind is produced a night, while 72% of power needs are during the day. In fact that Texas PUC only assumes 2.6% of line capacity in the resource calculations. Wind will be a part of solution but only a small part for decades.

We also evaluate the most sufficient natural gas units but generation capacity in the Texas market is already 72% gas fuel, which is much higher than the national average of 45%. Putting Texans even more at the mercy of imported gas is not prudent, and high vault of future gas prices would make it impossible to deliver stable low cost power. Then of course, generation have characteristics that make it attract is the low production cost and zero omissions. A nuclear energy like a long term solution to spend fuel storage and accommodation of cost that are twice that of co power generation, and a construction time line it could be up to 10 years eliminates nuclear as an option to meet Texas’s near term power needs. The unsubscribe total cost production is approximately $74 megawatt hour, $25 megawatt hour higher than for new coal plan. We still believe that nuclear generation can be part of the America’s future but working with others to potentially take part in a scale bill that could reduce both cost and construction time.

If the spent fuel problem can be solved and if we can reduce the capital cost by over 40% our commodity peak expansion is a potential, but this solution wont address our top fallibility charges until at least 2016 and likely much later. Of the options we have examined coal generation emerge as the logical choice to address the medium customer needs. The US has sufficient economic coal deposits that supply 250 years of power generation and coal is one of the main reasons why US electricity rates are among the lowest in the free market economy. The real question we had to answer was what type of coal technology to employ? The critical coals extremely economical to bill, potentially cost below 1000 kw, but the low efficiency and high emission profile do not meet our threshold for environmental performance, and a great classification combined cycle or IGCC has improve using the coal available to Texas generation facilities and in the large scale commercial environment. The two US units and operation their small heavily subsidized and have emissions profiles they were not as clean as their plants were building, neither units captures or sequesters seal to while IGCC units have the potential to deliver slightly lower machines they clearly do not off to the potential deliver savings relative to super critical coal.

Current capital cost exceed 1800 kw, not including the cost to capture co2 operation cost also compare on favorably capacity factors are expected to be lower than 85% and fixed on them more than double conventional coal. Over the life of the plant this could translate into prices that are $23 megawatt hour higher for customers relative to our supercritical coal plants. Even though IGCC technology does not work today for our customers, TXU is investing to commercialize it for the future with a substantial team working with a manufacturer full-time to make it a competitive choice. We also analyzed ultra-supercritical coal technology. It is also unproven on large scale in higher operating temperature and pressure demand parts that have extremely long lead times. Although life of the plant, the incremental capital cost could translate to prices, they are $16 megawatt hour higher than for our plants.

Based o our analysis, a supercritical coal generated facility proved to be the best solution today for our Texas customers and potential customers throughout the nation. It is 33% more environmentally efficient than the 2015 standard recently adopted by EPA’s Clean Air Interstate Rules. Perhaps most importantly, they can be built economically and in time to help lower prices and ensure adequate supplies by 2010. Slide 16 shows the most compelling market test in favor of supercritical coal. In Europe where CO2 emission rules have already being adopted and across US wholesome markets, 122 gigawats of traditional coal plants have been announced versus 13 gigawatts of IGCC, but they say in local review identifying supercritical coal is the right technology for today, we will continue to look for the more best solutions as Slide 17 illustrates.

We intend to be a leader in economic commercialization of the next generation technology and we are investing between $1.5 billion and $2 billion to achieve it. In Taxes we’ll support the FutureGen initiative to a long term power agreement. We remain committed to a zero emission coal facility, and we’ll invest to help make that happen. This discussion will also answer two related questions. Why build so much, so fast, and why not wait for the next technology? Texas is the 11th biggest electricity market in the world and our cost growth estimate show that more than 68 watts of new base low capacity will be needed by 2010 to keep pace with demand. This is equivalent to the total demand growth in California, New York, and Nevada combined. Without new supply reserve margins will approach a dangerous, unacceptable 7%.

The ability to bring enough plants on line in this time frame plus the company that can be build and scale and with today’s proven technology. Second benefit from scale of cost savings, slide 18 illustrates this point based on the typical construction cost of 14 to 15/KW, construction time is six years and average operations a typical coal plant can only deliver an all in price above $60 and megawatt out to customers delivering no savings. We’ve invested tens of millions of dollars in design hours, develop a plant that can be built for 11,000/KW run on line about 2010, address reliability challenges, deliver savings to customers and fund our $500-million voluntary emissions reduction program. Slide 19 reveals Texas has a strong legacy of power generation environmental performance.

Among the 10 most populous states, Texas has the second lowest NOx emission rate. Only California, a state that imports a significant amount of electricity from coal plants is lower. The DFW Area in particular has achieved substantial NOx reductions from power generations with help from TXU. Slide 20 shows the power generation accounts for only 3% of DFW Area NOx emissions and only about 2% of peak ozone. TXU’s DFW generation units’ accounts for less than one-half of 1%. Yes one-half of 1% of DFW NOx emissions. Based on preliminary results from air modeling specialists, our power generation program is expected to have a slightly positive effect on DFW Ozone.

As we were designing our generation program we wanted to get Texas access to the cleanest power generation fleet in the country. Our program will reduce our current total emission of NOx, SO2, and mercury by more than 20% the relative productivity improvement in terms of intensity is almost 70% and this is not taking into account the incremental 12,500 tons of NOx we will remove by displacing less efficient generation. We are making the largest voluntary reduction program ever in the US. As shown on slide 21 TXU would be the most environmentally efficient scale co-generator in the country with the lowest emissions of SO2 and NOx and the second lowest emissions of mercury. We will achieve this commitment at substantial expense and well in advanced of many mandated reductions last week we have the TCEQ to make the 20% reduction of formal requirement.

We believe that all power developers in the state should be held at this standard and put Texas on the path to the lowest NOx emissions in the country. Slide 22 summarizes the results of our power generation program. Number one, better reliability, TXU solutions will provide Texas with five years worth of urgently needed supplies reserve margins are projected above of safe levels within two years. Number two lower cost, TXU solution will save wholesale electricity purchases at $1.7 billion annually. Three, cleaner air, TXU will invest $2.5 billion to reduce key emissions by 20% and cut key emission rates by nearly 70%. And number four a stronger economy, TXU’s investments will create 21,000 permanent jobs, 40,000 jobs in construction and $14 billion increase in annual gross state products and tens of millions of dollars in local property taxes. Our program will also substantially reduce the likelihood of outages that stalk the Texas economy. Now Jonathan will continue the briefing.

Jonathan Siegler - Vice President, Strategy and Mergers & Acquisition

Thanks John, I would to discuss the TXU’s perspective on the uncertainty of potential greenhouse gas regulation. Reduction of greenhouse gas emissions is an extremely complex challenge that spans across society, fossil fuel generation accounts for approximately 38% of man-made emissions, while the transportation, industrial, commercial and residential sector account for the other 62% man-made emission account for only 3% of total worldwide emissions. Over the next 20 years the US is expected to add 1.8 billion metric tons of incremental annual emissions while the rest of the world is expected to add over 13 billion tons of annual emission.

Given the global nature of this issue the best solution would need to address all sources across all the world economies. Solving the challenge of greenhouse gas emission will require both technology based and the behavioral solutions and will come with a real cost that society must bear. We already see this cost today in Europe, where CO2 credits have added more than $10 of megawatt hour to the average price of electricity since 2005. Estimates place the cost of the Kyoto solution here in the US between $400 billion and $600 billion and $600 billion to $900 billion across the globe. Relative to the need to meet other major challenges it is unclear what choices US will make about CO2 regulation. As a commercial enterprise TXU’s role is to make the best choices based on the needs of our customers and potential policy scenarios.

From a strategic standpoint we examine uncertainty like CO2 the same way we examine other large uncertainties, we start by understanding the fundamental drivers create scenarios to understand the potentially impacts and design a portfolio that will be resilient to the different outcomes. One potential outcome is a mandatory cap in trade system similar to approach is better with hard success with other emissions, such as the Clean Air Act of 1990. Over the last 15 years while US electricity demand has increased by 31%, total tons of SO2 have been reduced by 50% in the generation sector.

Initial estimates of the cost to society were almost 5 time the actual costs. The program’s success is based on principles that have served as the basis for all the major programs that are followed. These principles are, first, a market based cap in system across all aspects of the economy and all impacted regions to achieve the needed reduction at the lowest cost to society. Two, an allocation of allowances that simultaneously provides industry with the flexibility as well as the capital incentives to solve the problem. And finally three, reduction that take place over a long period of time to allow technology to be developed and reduce the cost to society. Remember the initial stages of the Clean Air Act were institute at 1990 and the reductions continue through 2015.

These same principles will also apply to the US NOX and military programs in the Kyoto protocol in Europe. Well, we are not suggesting that a cap in trade program is the right answer, it is one of the many scenarios we modeled. If a program similar to the Kyoto protocol was put into affect in the US, it would impact TXU in the following ways; based on the average allocations in the UK, TXU would receive allocations for 70% of it’s current CO2 emissions and 40% of its future emissions from the new generation program. When the system came into affect the marginal cost would flow through to the consumer just as it has in Europe. In Texas, where gas would be on the margin the consumer would pay approximately $0.55 per megawatt for every dollar per ton of CO2 cost.

Comanche Peak would benefit from the expected increase in power prices. The combination of the higher prices in UK type allocations would mitigate the EBIDTA downside to the coal units. If the reduction path is similar to SO2 emissions allowances would be reduced by approximately 4% each year. We’ve modeled an MPV cost for the TXU portfolio over a long period of time with less than $500 million based on a clearing price of CO2 at $20 a ton. This cost could be further reduced with breakthroughs in technology that lead to more economic sequestration. We are highly confident that these breakthroughs will take place and we hope to play a strong role in developing them.

While this is just one of the many scenarios that TXU may face, it represents the impact without changes to the portfolio. We do this challenge as an opportunity to create value for our customers and shareholders. Just as manufacturers like Toyota have been proactive in providing lower emission hybrid vehicles, TXU will be responsive to our customers’ desires for CO2 free products. We are evaluating a zero CO2 retail electric product that first will be linked to zero carbon generation like wind and nuclear. We are currently the largest nuclear generator in Texas and one of the largest wind purchasers in the US. We could also buy credits for certified CO2 reductions from formal processes such as the joint implementation, CDM program and the Chicago Climate Exchange to offset our other production emissions.

Unlike customers of some regulated utilities who are held captive to uneconomic and unproven technologies, TXU will let it customers have the freedom to choose. TXU will also continue its strong record of voluntary CO2 avoidance and elimination. We have reduced the eliminated or sequestered the equivalent of $262 millions of CO2 since 1991 and over 25 million tones in 2004 alone. Our program, the result of which reported to the Department of Energy represents the largest voluntary reduction of any US investor owned electric utility and the second largest reduction in country.

We believe coal plants can be part of the CO2 solution also. Slide 24 shows that over the last 40 years coal plants of improved their efficiency 33% corresponding directly to a 33% improvement in CO2 emissions intensity. We believe that super critical and ultra supercritical coal generation can approach 55% efficiency or a further reduction in CO2 intensity by 10% to 15%. Across the globe there are over 650gigawatts of inefficient coal plants that run with an average efficiency of 29% replacing that new efficient coal plant could reduce their carbon intensity by up to 36% and cut 1.4 billion tons of carbon worldwide. While some people believe CO2 constrains will hurt the coal industry, we believe that as a short sighted view. The same belief existed 30 years ago with the creation of CO2 constraints. Similarly with over 300gigawatts of installed coal capacity and almost 2000 kilowatt hour coal generation in the US alone every dollar per ton tax sends a $2billion annual value signal to reduce the CO2 intensity of domestic coal generation. While they are not economic solutions today, we believe in the next 15 years there will be technology that will reduce carbon emissions and super critical coal in the $5 to $15 ton range. We intend to leave their commercialization.

Texas is also well suited for potential sequestration to enhance the recovery and we have already begun discussions with oil companies to pilot this type of initiative. Whether it’s by the displacing all the inefficient coal plants with new efficient units or by providing the industry with a low cost carbon retro fit solution. TXU believe there is significant opportunity to create value. Finally carbon constrains would create the need for provider of integrated solutions. Carbon regulations will create complex decisions for companies, should I retrofit, should I buy allowances, should I shutdown. As we explore all the aspects of the carbon value chain, we will be in a position to help optimize these positions. For instance, we can potentially provide alternatives to regulated utilities that are building high cost experimental IGCC plans. An alternative may be to build an efficient super critical coal plant and use the savings to eliminate less efficient sources of CO2 omissions both domestically and around the world.

Slide 25 shows the cost of CO2 mitigation from a variety of sources across the economy. Based on the current price of clean develop and mechanism project which currently trades for less than $10 a ton, a utility could actually deliver customers an economic source of power while eliminating real greenhouse gas emissions at levelized cost of $13 and megawatt hour less than proposed cost levels. The benefit of this alternative, alternative approach or even more apparent given that announced IGCC projects did not get include any plans for co2 capturers or disposal. Similar to all on certainly TXU basis we are always focused on developing a business model that will profitably respond to the energy challenges our customers face. This is good strategy and good business. I will now turn it over to David.

David Campbell - Acting Chief Financial Officer, EVP Corporate Planning, Strategy and Risk

Thanks Jonathan, this morning I will recap the financial results for the quarter, update you on our financial hedging strategy, and discuss our outlook for the year. As John noted our Q2 reported net income was $1.7 per share compared to $0.70 in ’05. Year to date net income was $229 per share compared to $0.60 in ‘05. Special items in the Q2 totaled $0.52 and fall in to three parts. First the 28% charge and the impairment of our natural gas fire generation facilities in light of their likely sale or retire, and second the net effective adjustments associated with the new Texas margin tax equal to $0.9. The third item is the $0.15 per share charge associated with the day one book loss for series of large natural gas pit transactions for the power development company. These special items are rolled on cash.

As shown on slide 27 operational earnings for the quarter equaled $1.59 per share, a 104% increase over Q2 of ‘05. These results also reflect cash flow hedge and effectiveness gains of $0.20 per share and the benefits of warmer than normal weather of up to $0.9 per share partially offset by lower than average usage. Slide XXVII and XXVIII highlights the operational earnings growth in TXU Energy holding. The strong performance and profitability of TXU’s solid fuel plant both the nuclear and lignite units were the main growth drivers. Result also benefited from ongoing cost leadership excluding electric delivery, total operating cost and SG&A expense is equivalent by 9% relevant to Q2 ’05 as shown slide XXIX. TXU Electric Delivery’s operational earnings were flat relative to Q2 ’05. Higher revenues from warmer weather growth and increased transmission revenues were offset primarily by timing of expenses associated with reliability improvement initiatives, appreciation expense and income tax.

On a consolidated basis relative to the Q2 last year, reduced shares outstanding improved operational earnings by $0.7 per share. We’ve repurchased 16.5 million shares here today leaving approximately five and half million shares remaining under the authorized ’06 program. Excluding effect of reduced shares net corporate and other expenses were essentially unchanged from the Q2 ’05 reflecting higher interest expenses in a positive contract settlement. Slide XXX highlights the company’s credit matrix, which continue to show substantial improvement. Relative to the first half of last year operating cash flow has increased by more than 200% to 1.9 billion. From a trailing 12 month perspective the interest covered ratio increased by 29% to 5.5 times. The debt to EBITDA ratio declined 38% dropping from 4.0 to 2.5. This is the sixth consecutive quarter in which these matrix have improved. A comparison to other companies in the electric power sector also shows the same positive trend as illustrated on slide XXXI. Based on our matrix of the past 12 months, we are now on the top four tier in the industry for interest coverage debt EBITDA and debt enterprise value.

We’ve also improved the resiliency of our forward cash flows through our standard hedging program, which we launched last fall. In the Q2 we executed an additional 600 million MMBtu of natural gas hedges. These hedges along the subsequent activity in the Q3 bring the total size of the national gas hedging program to just over 1.3 billion MMBtu. This hedging program has two parts. First for the base business, we have offset more than 95% of expected gas price risk of 2006 to 2009. This significantly increases the resiliency of TXU’s three year cash flows to down size commodity cases. In the first half of the year, the business’s ability to withstand significant volatility in near term gas prices to provide a good example it has in operation. Slide XXXII shows our estimated commodity position from 2007 to 2009 for the business. As shown on slide XXXIII TXU’s resulting exposure to commodity and heat movement is very low, far or less than it would have been without the hedge program.

The second focus of the commodity hedging program is TXU Power Development Company. In the Q2 TXU entered a significant amount of hedges as a development company. Later this fall we also plan to assign the appropriate number of hedge contracts from TXU entity holdings to support the new company’s target credit rating. These hedges will serve as an important enable our financing strategy. As we described in our last call earlier this year we undertook a systematic review of alternative strategies to finance the new power generation investments. We selected non-recourse project financing complemented by a partial sale down of equity as the approach that would optimize the cost of capital and the program’s risk return profile. This approach leverages the strength and debt of the capital markets. It allows other equity partners to participate without having -- financing.

In June TXU Power Development company secured an $11 billion financial commitment syndication is expected later this fall. Funding will contingent on the issuance of permits by the TCEQ and other typical condition. A total of debt level in key ratios should compare favorably with higher leverage in region project financing. For example total of debt levels for TXU Power Development Company amounts to a loan to value ratio of less than 65%. An important feature of the financing structure is that under the terms of the commitment, TXU Power Development Company’s debt will be non-recourse to the parent company. This structure provide yields for TXU Power Development Company get investors that reflect the unique feature and risks of new plant construction thereby matching investors with a specific asset class and appropriate pricing.

Slide 34 highlights the relative risk return benefits for the selected financial structure in different commodity environment. In case one, an un-hedged approach with no project financing creates the most significant volatility in value. A 25% downward shift, the entire forward curve would cost TXU equity investment to break even and any additional reduction would result invalid destruction. In case two, hedging without project financing reduces the volatility and provide protection down to 32% downward shift in the forward curve. Finally in case three which is the current baseline the combination of hedging and project financing, gas volatility to highest degree and limits the impact to equity and existing debt holders.

TXU has received substantially from potential equity investors in the development company. TXU is particularly interested in equity partners who are attracted to the long-term prospects for this after class and have access to low-cost capital. We are working with Morgan Stanley and Citigroup as our advisors in the equity sell down process. As part of this process the information memorandum is expected to be distributed later this month. My final topic is our earning tabloid, which we are maintaining for ‘06 and ‘07. Excluding the impact of hedge and effectiveness the range for ‘06 operation earnings is 550 to 575 per share split roughly 64 in between Q3 and Q4.

In ‘06 TXU will be making significant investments in our power generation program both in (inaudible) and a pre-permit capital expenditures. And this expenses are not expected to result in a change in our outlook range. Total CapEx for the development company this year is expected to be roughly $1.2 billion including approximately $400 million we expect to draw on the project financing. The remainder is expected to be eligible for imbursement and the power development company wants to permit their issue and other conditions are made in 2007. In summary, we had a strong quarter we made significant progress in advancing our financing and risk management strategy and we are progressing well with our generation program. This concludes our prepared remarks, we will now open the call to your questions.

Question-and-Answer-Session

Operator

[Operation Instructions]. Your first question comes from Paul Paterson.

Tim Hogan

Hello Paul, Paul?

Paul Paterson

Can you hear me?

Tim Hogan

We can hear you.

Paul Paterson

Okay, thanks for your update -- your Q information I think that’s really helpful. With respect to the $500 million MPB would be a Kyoto UK scenario that you guys describe. Is that 70% allocation apply to global plants that guys have announced or it’s the 40%?

John Wilder

I would ask Jonathan to clarify. It only applies to our current production the way Kyoto works is even new production that the participants are putting in to service over a period of time qualified for an allocation, but I’ll have Jonathan give you the details, Paul.

Jonathan Siegler

John is exactly right, the scenario we modeled was 70% allocations for existing generation, which we consider our coal plants that are operating today and 40% allocations for the new generation plants that we come on line in 09.

Paul Paterson

That’s excellent, and then finally the $350 of KW in scale efficiencies that you have, I know you’re very confident about where you are in the process and everything, but if for some unforeseen reason only some of the plants got built, how does that change the economies of scale if you follow me? In other words, obviously by building some of these plants you guys have the economies of scale. If there was some reduction on the number of plans, is there some easy rule of thumb as to how the economies of scale are impacted?

David Campbell

It probably wouldn’t impact it at least in this realm, Paul. If we ended up building a few less plants in (inaudible) we would make some minor retrofits to those boilers and we would -- those power islands into another market. So at least for this first round to build out we can’t see any reason that -- that would make a big difference.

Paul Paterson

Okay, great, thanks a lot.

David Campbell

You are welcome Paul.

Operator

Your next question comes from Dan Eggers.

Dan Eggers

Hi, good morning, the first question I guess I saw you guys open your office in the development side, well probably too early -- in Texas -- can you give us any color on progress and expectation for the market at this point?

John Wilder

Yeah, I will give you overview Dan, and then I’ll ask Mike Childers to give you some more detail specifics. We have looked at over 150 different sites in a -- you know like call it a modest amount detail, we have got a fairly disciplined screening process that peels those sites down using a number of variables whether it’s access to water, the size of the footprint of the size -- transmission access, those kind of things. We are now down to detail site assessment of about a dozen or so sites that look quite promising and overall we feel real good about the works we are doing there and our ability to execute that permit -- final permits by the end of year. But I would like to have Mike give some more color, because he and his team on the ground there and they can give you or Mike can give you some more detail.

Mike Childers

Yeah Dan, as John indicated we’ve looked at numerous sites and are focusing on those right now, that will provide us some development -- some enhance speed to market as well as some low cost entry point. So we are focusing primarily on Brownfield type of opportunities that have rail access, that locations that will provide for permitting for the types of assets we want to construct. We’ve narrowed down the 12 sites and will be advancing those by the end of the year.

Dan Eggers

Great, I guess Johnny kind of opened this out in your comments, but the idea with some of these folks at IGCC and obviously it’s got a lot of attention kind of in core PJMs as far as development goes. Do you see interest in this idea of delivering these lower cost alternative as another form of reducing CO2 or reducing some of these emissions issues as you guys look at these in PJM development search?

John Wilder

Yeah, quite frankly Dan, the advantage of PJM is there are so many old inefficient plants in the stock that are super critical coal plant like our reference plant can actually reduces SO2, NOx, mercury and co2 just by displacing the older generation. The challenge that we have IGCC and I would, I think we probably have more people and more engineers on the ground working in IGCC in a detail commercial way than any competitor in the space. They would really find out you know, when it will work and what conditions need to change to make it work properly. But right now IGCC wouldn’t provide the savings to the customers. The big issue for the industrial customers particularly in PJM is price. They want nickel power and IGCC can deliver nickel power our super critical co program can deliver nickel power and it can delver reduced submissions including co2. So the discussion we were having are more just like the oil, they are around reliability, they are around price and they are around making a positive impact on the environment PJM just happens to be configured in the way that you can just like we have been able to doing in our -- we’ll be able to do all three.

Dan Eggers

Got it, and I guess one last question with the Share buyback coming to happy conclusion here, any thoughts that you guys might address that issues again?

David Campbell

We are continuing to look at that dam where we are getting, you know, we go through our annual capital occasion the forward plan work every summer, we are looking at these PJM opportunities to see what our forward capital requirements might be, we put all of those opportunities including our share re purchase to our capital allocation proper that we described and we will just judge, we will judge the share repurchase opportunities against the other investment opportunities we have over the coming next six months or so.

Dan Eggers

Got it thank you guys.

John Wilder

Thanks Dan.

Operator

Our next question comes from Steve Fleishman.

Steve Fleishman - Merrill Lynch

Yeah, Hi, John.

John Wilder

Hi, Steve.

Steve Fleishman - Merrill Lynch

Couple of questions, first in your earnings release the vertex you devco, the amount of gas equivalent that is expected to produce in all time is like 500 and there have been 585 is that, based on assumption that gas is on the margin less than you talk before or what, why is that the case.

John Wilder

Right Steve, I’m going to ask David to explain it to you, but before he explain it to you but I want to warn you, he is going to torture you.

Steve Fleishman - Merrill Lynch

John Wilder

So this is the torturing response that’s a great question and one that we need to be responsive to and David’s got his finger on the pulse of our forecast approach.

David Campbell

I will take that as a feedback in advance to my attempted -- what representative is that the fine calculation of our adult international gas position it’s not actually change in our forward heat rate assumption, this is a more accurate calculation of what the gas price exposure in for devco and reflects really underlying methodology we use for our base business. So it’s a correction of June estimate there is also some refinement for changes. In other words of you say for an example you are assuming an heat rate clearing heat rate in 2010 relative to the Houston ship channel. If you just multiply the underlying share watt hours of production of the business by that heat rate, you will overstate the gas position, you can use that heat rate to calculate EBITDAs or EBITDAs is more correct and continue to be, they are unchanged from the last estimate. But you need to reflect the time and colors on the market and you underline gas position calculations. So in another words, when you calculate your gas position you will be using a factor that’s lower than the 7x24 heat rate. Because a portion of the time gas is on the margin, so it’s not a change in our expectations and how much gas should be on the margin, it’s a correction to the estimate that we had in our prior release.

Steve Fleishman - Merrill Lynch

Okay, and I guess one other number I just be curious, do you have a number for ‘010, you given us on the base business before but given your new hedges what the gas sensitivity of the entire portfolio is, to I would say a dollar changing gas.

David Campbell

Yeah, we had our net exposure listed on the table 10 as you see on the release, so the net exposure there is including the plant for power sales and the hedges that we haven’t places as well the debt exposure, that’s a 150 to 200 million MMBtus, so it’s a 150 to 200 million of EBITDA annual exposure 2010. One dollar move would be a 150 to 200 million of EBITDA for the combined business.

Steve Fleishman - Merrill Lynch

Right, okay, and then I am curious any update thoughts on the potential future of the delivery business, you know structural change etc.

David Campbell

Right, we continue to review all of our options around -- actually all of our business is -- probably with particular focus on deliveries we think there is a great opportunity to find a technology partner for delivery as well as a capital partner that will allow that business to really flourish and the some of the challenges that face the reliability of the energy infrastructure in Texas that I described earlier in my comments particularly apply to electric delivery. We are going to need to implement technology and we’ve got a CapEx program and that business is about three times the normal CapEx program, we have had a over the last 20 years so. We like the idea, we continue to work it and we’ll continue to work it in till we can really put that business in a good position.

Steve Fleishman - Merrill Lynch

Okay, one last quick thing. Since the time you announced your new bill pretty much every other company in the sector who has commented on it has doubted your $1,100/KW cost. I just be curious with all the new data you gotten over the last quarter, if you could just update your conviction on hitting the $1,100?

David Campbell

Yeah, I certainly understand why they doubt it from the standpoint when they start looking in detail and go to the market to try to get any of these single plant bill they probably are continuing to zero around of 1400KW, 1500KW, 1600KW number. Some of these plants we have seen have been estimate is high as 2,000 particularly in regulated markets where as you know, Steve they have a difference incentive, but we feel very good about our estimate. We’re well on our way and our engineering work, we have 20 of our lean workup sessions already completed. We’re essentially 50% through with the supply chain work which is we’re really all the action is on this making sure we’re accessing the right global low cost manufacturers. In fact shops and we’re not seeing any reason to not believe that we can deliver on that and the other thing that we are finding that we’ll build actually even a stronger conviction on and we really doubt the ability of the single plan developer to actually get these things done. This is the -- global market for all these materials. It’s a tight global market for the engineering resources and if you don’t have a scale bill program where you can throw some weight around in the market in the supply chain where you can get access to the right engineering talent, where you get access to the right construction project managers, it’s going to be difficult for the single plant developer to pull on to these off. So we’ve actually become even more encouraged as we’ve gone to the details because of – encourage in our ability, deliver, and our performance levels but also encourage that any one of the competitors just aren’t going to be able to pull it off.

Steve Fleishman - Merrill Lynch

That’s great thank you, John.

Operator

Your next question comes from Vic Khaitan.

Vic Khaitan - Deutsche Asset Management

Yes, thank you. John, two-part regarding this new program, new building program, one being that as a follow-up to Steve’s question about -- many people are doubting about finishing this thing, so what might be the critical item which might delay this program and then I have a follow up question about the environmental issue.

John Wilder

Well there is like any of these things they gets probably something that we don’t see coming as we look at just the facts before us today you know, you would always sort of put a lot of focus on the permitting process, that’s a -- in many ways it’s a scientific process but can become a political process. We feel good about where our permit is positioned, we feel very good about the permit that we -- that application that we files and with our offset program, we think it makes it very compelling but that’s always the key, go/no go position. We feel good about the access to all the critical materials but it is a -- a global supply chain now. If any of these fabrication plants or a manufacturing facilities were to have you know, major problem either due to unexpected weather bent or terrorism or you know, who knows what it could be a major labor strike that causes the whole program to be shifted around. So you know we are very mindful that we are competing with China, we are competing with India. China is building out 60 gigawatts a year of productions so when they want it they jumps into this business and tries to compete with those big kind of buyers is always going to be subject to be pushed around in the queue. We feel good about it, we’ve got a very qualified and challenging team working it, we’ve got the -- clearly the two best constructors in the world for a coal plants. They exclusively work for TXU, they were the only two EPC contractors that have delivered any material coal plants over the last couple of decades. So we thing we got a position above as well as you can position it but you know I don’t -- it will certainly be -- it will be confronted with some supply chain problems there is no doubt about that but we think we can weave our way around it.

Vic Khaitan - Deutsche Asset Management

Okay, thank you. And on the environmental side, while you are saying that you have a pretty good control over what you think will reduce the emissions as well as to meet the society needs but there are some new technologies you also mentioned and those technologies will perhaps improve some of the emission control. So are you flexible enough in your thing that you can upgrade these plants or they have to re-plan new plants to employ those new technologies.

David Campbell

Dave, on the super critical co-plans all of the retrospective technologies that been developed for what they call CCS, Carbon Capturing Sequence applied to the new super critical. They require high temperatures, they require high heat performance. As Jonathan mentioned there is a $200 billion opportunity for value creation if the world decides that they want to place a prize on carbon and if that value opportunity unfolds, we’re confident in the work that we have done was some of major manufacturers particularly the retrofit manufacturers, they will be able to retrofit some of our new technologies. Now, some of the old plants, the sub critical scale plants will be more challenged and the lower thermal efficient plants will be challenged. So the plants that Jonathan described across most of the world and quiet frankly most of the east coast these 28-29% thermal efficient plant, they are going to be challenged to retrofit. But these new ‘40s kind of efficient plants will be good candidates and most of the retrofit estimates that you see actually compete very favorably and beat most of the full all in cost estimates for both nuclear generation and IGCC. So it’s going to be a horse race for what technology wins in a carbon constrained world. Europe spreading on the super critical and the evidence is overwhelming there. The new build outs in Europe 50% of the new generation that’s being installed in Europe is super critical coal and they have a constrained economically on the carbon emissions. So, there is a lot of research going into it. There is a lot of work and we’re going to be part of it.

Vic Khaitan - Deutsche Asset Management

Okay, thank you very much.

David Campbell

Thanks.

Operator

Your next question comes from Danielle.

Danielle

Hi, I just was wondering, is there -- in your mind in order to keep the program on track such a number of permits that you do require in order to really keep the schedule on track by year end or by a certain time, because that is something that’s really independent from your judgment or your work.

John Wilder

Yeah, well I am just kind of thinking off at least the top of my head, and now I’ll ask some others to jump in on this, but I think for this to really work the way we’re wanting it to work. We would -- yeah, one we expect to receive all the permits but two, if we received at least three quarters of them, we can continue to make it work, because we would slide those other plants over to other markets.

Danielle

(Inaudible) contingency plant, it just in case that it gets bogged down in -- in the political arena, but you still need the minimum amount of tonnage in order to get things going I would assume?

John Wilder

No, exactly, I mean we -- you know we are racing, we know we are racing against the clock for our customers, we have got to get these plants into production or we are going to be in a really deep soup in Texas. And so, this is the way to get it done, any delay cost our customers money in terms of direct savings result in higher admissions in Texas and also puts substantial economic harm potential for reliability problems. So we are trying to, we are working our tails off to try to get this thing done, and we think -- inform public policy makers who understand what we are trying to achieve, and who we were been able to spend time with, share in that same commitment to keep this Texas economy moving and keep power flowing and keep good low-cost power in Texas to make our customers happy. So we are, you know, those statistics I gave 4 to 1 in the counties favorability rating in the counties in which we are building these plants. 2 to 1 broadly statewide. It’s very difficult to find any topic in the general, you know, general population that drives those kinds of favorability ratings these are very, very high, there is a lot of public support for people understand this problem that want to sit down and listen to the facts and we feel real good that we are going to be part of solving this issues for Texas.

Danielle

Thank you.

John Wilder

Thank you.

Operator

Your next question comes from Ryan Orson.

Ryan Orson

Hi, good morning. I have two questions. First, I was wondering if you could expand a little on the benefits and strategic rationale for the infrastructure deal -- makes bringing in a capital partner there easier to do, and how might it effect the timing of binging someone in?

John Wilder

Ryan, I ask Tom Baker to respond to that he has been in the details of the infrastructure deal and is very supportive of it he and a team have been working this for quite frankly a very long time. So we plant it out well, follow through well and we are about half way through the detailed execution.

Tom Baker

Thanks John, yeah the infrastructure thing, I think gives us some real benefit one from the implementation and facilitating our strategy implementation which is to grow this business outside of our footprint by having a national or employer that knows a labor markets throughout the sate and in the United States I think will be very helpful from that standpoint. From the electric delivery business we can reduce our cost over the term of this agreement probably save $100 million over the term of the agreement which you think is very important these days and helps us to put in more technology to improve the liability and kind of control the cost to do that. And we will contribute to the reliability improvement, we got a lot of expertise from folks -- in fact, some of these folks we have done business work for years. Some of the contractors that are part of the infrastructure group that work on our system I would guess were about 40 years they know our systems, they know us, they know our service territory and (inaudible) so as we go forward and we also got opportunity course relative from the transaction so that happen in regular business so I think we will be very positive from our standpoint to get this implemented and we are well along away to do that.

Ryan Orson

It would have any impact on you thoughts about strategic options for the Texas T&D business?

Tom Baker

Yeah, clearly, but I think it’s got an impact on the strategic options for the T&D business in United States. Personally, what we are trying to do through our strategy is approach the spirit of the future some folks are talking about the 21st century grid around the country, to improve reliability, that’s going to be demanded in this digital society and the structure at I think is gets implemented, it is going to be viewed as a way to more efficiently, effectively on a better cost basis deliver these T&D kind of services and provide that as we go forward.

Ryan Orson

With regards to bringing in a capital partner is that, does that play any role in the transaction?

David Campbell

Ryan, I think it certainly makes it more attractive to the potential technology partner and capital partner because this is a business that has growth potential beyond the traditional regulated territory that our T&D business has.

Ryan Orson

Got you, one other quick question follow-up on Danielle’s question with regard to the EPC contractors you have –- I believe you have agreements with -- for the Texas development plant. How would those agreements work if you, say you got 75% of your permits in Texas and you decided to move another part of your development project to PJM or another market, do those EPC agreements also -– would those be able to go with that move in the project?

David Campbell

We think so, Chuck is shaking his head, I don’t think we contractually complicated that or build that in, but we wouldn’t see any reason that those wouldn’t slide over. Now the subtlety though is would we have exclusivity in those other markets and I don’t think we would comment on that right now that we could certainly get it, but all the other terms of the agreement should apply.

Ryan Orson

And if you didn’t follow your project to PJM for example, how would that effect the timing of bringing plans on line and construction cost?

David Campbell

It probably would be a little higher construction cost it will be a little bit of a delay. But it wouldn’t be materially, it would be like the Texas process, it would start off with the critical path of permitting process and then the overall construction timing should about the same. Cost would be a little bit higher, put a wet scrubber on -- dry scrubber I think that’s 75K I’m looking around about 75KW or so, labor is going to be tag more I think we have estimated maybe a couple of bucks more -- 4 million so, that tally is up a bit but generally we think we would delivered in the same general cost profile and time profile is very positive here.

Ryan Orson

Okay, thank you very much.

David Campbell

Thanks.

Operator

Your next question comes from Terry Miller.

Terry Miller

Good morning, two parts of question and that is in looking at your $11,000 and KW just to go back to that question a little bit, can you give us a sense of what type of on a broad percentage basis, contingencies in that number when we try to compare it to other people that might have a 15% or 20% contingencies and let’s say a $1400 KW number and then the second part of the question, John if your could, do you have a sense base on how much progress you made in coming up with your contracts to date. What percentage of that 1,100 you feel is lock in at this point?

John Wilder

Yeah okay I’m going to ask –- will start with -- jumping on this answer -- is broadly we have less than 10% contingency built in, we think building in a big contingency shows not high performance, that leads sloppy execution, so we have got less than that built in but, we’ve got a lot of these costs locked down. We got about 50% of the purchased components already nailed down. We are working on the others. The big items that we’re worried about -- boiler and the steam turbines, we have nailed down now it’s the auxiliary equipment -- Steve to describe simple work that we are doing there and the confidence that we have in the supply chain market to be able to come into our estimates.

Steve

Yeah, we are aggressively managing issues, I mentioned before by working up supply chain market with our EPC partners and we selected Bechtel and Fluor because of their strength in this area. That was one of the key parameters in selecting them. But we’re for micro boilers we are manufacturing those in China where growth has slowed somewhat for the boilers and we are all slated to get a substantial modem, GE is manufacturing capacity for large turbines in New York and get (inaudible) for the forgings due to the scale of the program. Scale is a big issue and that’s working to our advantage. We reserve space already in the steel mills upstream with the fabricators. Our fabricators have access to the materials for raw, there are -- and we are also making adjustments to our construction schedule offer fabrication and tanks onsite to eliminate delays. So we are been very flexible in the way we find our lean construction and lean design approach as to let’s say how we are going to even operate the plant. So, we are doing a lot of this upfront right now in terms of how we are doing the lane construction and design as well as working up supply engineering market itself to minimize any potential growth in the cost or the schedule.

Terry Miller

Okay, and a totally separate subject, you put in place another $1.6 billion credit facility, it takes you energy, and I was wondering what the rationale for that additional financial flexibility was.

David Campbell

This is David, there are two reasons for, one was that we were doing some long term debt with some of the shorter term facilities so we covered some of those and second with our expanded hedging program we want them -- just ensure that we have ample liquidity so that those the two main drivers.

Terry Miller

Okay, and do you -- is there any additional update on the (inaudible) and where does that stands?

David Campbell

This is David again, we noted in the prior release we are setting up a lien on ground to support some of the hedges into more -- liquidity efficiency to proceed with and we can do so under our (inaudible) so, we expect that lean in the inflation within the next month, that would free up some additional liquidity and we expect we noted in the release that will support, some of the hedges that the development company to the time of permitting and then those will -- all those hedges will be supported by the action of the Development company, the lien if it stays in place would only be used to support hedges at Energy.

Terry Miller

And have you gotten buy in from the rating agencies that that will not cause any rating down graded energy.

David Campbell

We’ve had -- we’ve kept the agencies informed about our plans along the way, we are planning to do a thorough review, this fall not only of the Development company in our -- in the financing plans for that structure but also we always go through a thorough review in the fall about our forward financial plans, as John mentioned we always go through our plan at that time. So at this time we will go through that with them in the fall. One think that they recognize and I’m sure you reorganize as well is that the reason why the lien structures for big ground is an efficient one for hedges and overall is one that’s a pretty efficient way to approach the program, it’s the right way risk element in other words if the hedge is -- the hedge program that we have in place, the hedges go out of the money it means that the commodity pricing environment has become more robust, prices have gone up which tends to increase the underlying value of the assets and the security. But he overall discussion with the agency is -- this fall.

Terry Miller

Thank you very much.

Tim Hogan

We have time for one more question, Amanda.

Operator

Your next question comes from Michael Lapides.

Michael Lapides - Goldman Sachs

Hi, guys Michael Lapides from Goldman here, one quick question just after the 9000 megawatts are built, how do we think about what’s s the ongoing capital spending the energy would be?

John Wilder

Oh, Michael I’m going to it’s David jumping on this but I, you know, our estimates are going to be have a pretty wide range around that --

Michael Lapides - Goldman Sachs

Assuming you didn’t build any more new plans after that and it’s just maintenance CapEx?

John Wilder

Oh, I see what you saying, yeah -- probably about $600 million -- David has comment on it.

David Campbell

Typically most of the CapeEx as you know is in the power division.

Michael Lapides - Goldman Sachs

Yes.

David Campbell

It has ranged in 300 to 400 million range for maintenance CapEx, it’s a little bit higher this year because we have a big steam generator replacement program for Comanche Peak, next year, so it’s north of 400 but typically that maintenance CapEx range would be in the 300 to 400 million range that’s what the base slide is.

Michael Lapides - Goldman Sachs

And how would the adding the new 900megawatts impact it?

David Campbell

Well, those are going to be at the development company so we will tend to look at those in a separate basis right the TXU power will be in a separate entity than the development company so those estimates would be to let those -- we group those separately that. Jonathon is going to --

Jonathan Siegler

Between $50 million and $75 million additional maintenance in CapEx.

David Campbell

It’s much lower given obviously that the plant are much newer, different profile for the plant.

Michael Lapides - Goldman Sachs

So when I think about your total maintenance CapEx on generating plants it would be after 2010 or 2011 timeframe, you are talking 350 to 475 million roughly?

David Campbell

I would say in the 400 to 500 million range is fair. There will be the longer we take it out the numbers may go up a little bit for the existing units, the results get older but I think the numbers that you -- are generally in the range.

John Wilder

All the operators around the table Michael are shaking their heads, so that means shave a $100 million of the number, and it’s probably --

Michael Lapides - Goldman Sachs

Okay, thanks guys.

David Campbell

Thanks.

Tim Hogan

Thank you all for joining us today, the Investor Relation’s team will be available on the phone if you have further questions. We also plan to be at the Lehman Brothers and Merrill Lynch Conferences in September. We look forward to seeing you there. Good-bye and thank you for joining us.

Operator

This concludes today’s conference call. You may now disconnect.

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Source: TXU Q2 2006 Earnings Conference Call Transcript (TXU)
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