Good day, ladies and gentlemen, and thank you for standing by. Welcome to EnCana Corporation's Second Quarter 2010 Results Conference Call. [Operator Instructions] I would now like to turn the conference call over to Mr. Ryder McRitchie, Vice President of Investor Relations. Please go ahead, Mr. McRitchie.

Thank you, operator, and welcome everyone to our discussion of EnCana’s 2010 second quarter results. Before we get started, I must refer you to the advisory on forward-looking statements contained in the news release, as well as the advisory on Page 49 of EnCana’s Annual Information Form dated February 18, 2010, the latter of which is available on SEDAR. I’d like to draw your attention in particular to the material factors and assumptions in those advisories. In addition, I want to remind everyone that EnCana reports its financial results in U.S. dollars and operating results according to U.S. protocols, which means that production volumes and reserve and resource amounts are reported on an after-royalties basis. Accordingly, any reference to dollars, reserves, resources or production information in this call will be in U.S. dollars and U.S. protocols unless otherwise noted. To provide a clear understanding of the new post split EnCana, the prior period comparative information discussed in this conference call represents EnCana's financial and operating results on a pro forma basis. In this pro forma presentation, the results associated with the assets and operations transferred to Cenovus Energy are eliminated from EnCana's consolidated results, and adjustments specific to the split transaction are removed. Financial information that reconciles EnCana's consolidated financial statements, and pro forma financial statements can be found in EnCana's news release dated July 21, 2010, available on our website. Randy Eresman will start off with the highlights of our operating results; Mike Graham, Executive Vice President and President of our Canadian division; and Jeff Wojahn, Executive Vice President and President of our U.S. division, will then each speak to their areas before turning the call over to Sherri Brillon, EnCana's Chief Financial Officer to discuss EnCana's financial performance. Following some closing comments from Randy, our leadership team will then be available for questions. I will now turn the call over to Randy Eresman, EnCana's President and CEO.

Thank you, Ryder, and thank you, everyone for joining us today. Today's call will highlight EnCana's performance during the second quarter of 2010. We're now at the midpoint of the year, and we're pleased with our results to date. EnCana's second quarter 2010 results were solid. Cash flow was $1.2 billion or $1.65 per common share diluted, and operating earnings were $81 million or $0.11 per common share diluted. Second quarter capital investments totaled $1.1 billion excluding acquisitions and divestitures. During the first sixth months of the year, we've invested just over $2.1 billion of our planned $5 billion capital program. Year-to-date, cash flow was $2.4 billion. We've updated our 2010 corporate guidance, adding another $500 million to our annual capital budget. This additional investment will be used to advance the development of our key and emerging resource plays in Canada and the United States. Our 2010 production is ahead of target, we've increased our 2010 production guidance to average 3.365 Bcfe/d for the year. This equates to a 13.5% growth rate per share for 2010. As well, our year-to-date operating costs were 17% lower than guidance. Accordingly, we reduced our operating cost guidance to $0.80 per Mcfe. We've adjusted our 2010 NYMEX pricing assumptions downward from $5.75 to $5 per Mcf, although our cash flow range remains unchanged at between $4.4 billion to $4.8 billion per year. Our updated guidance is available on our corporate website. EnCana's quarterly average production volumes are more than 3.3 Bcfe/d, an 8% increase over 2009 second quarter pro forma volumes. On a per share basis, second quarter natural gas production increased about 12% compared to the second quarter of 2009. I'll now turn the call over to Mike Graham, President of the Canadian division of EnCana to discuss the Canadian division results.

Thanks, Randy. In the Canadian division production, volumes for the quarter were approximately 1.4 Bcfe/d, a 3% decrease over pro forma volume for the same period in 2009, and nearly a full 12% increase over first quarter of 2010 volumes. So essentially, we're up about 150 MMcf/d Q1 over Q2 in 2010. The year-over-year decrease in volumes is primarily a result of divestitures, we sold back around 100 MMcf out of Canada in 2009. Whereas, our quarter-over-quarter production increase was due to steady growth, lower royalties and play optimization at Bighorn, Cutbank Ridge, which includes our Montney play and Greater Sierra, which includes the Horn River shale play. In the Horn River, EnCana net production averaged around 24 MMcfe/d during the quarter. In late May, we started up our Debolt water processing operation, sourcing non-potable water for use in our hydraulic fracturing. We expect that over time, this initiative will reduce our costs, as well as our environmental footprint in the area. Year-to-date, we've drilled ten net wells in the Horn River. We continue to see increased operating efficiencies, and higher production and recoveries from drilling the longer lateral. We've now drilled one well in the Horn River to a total measured depth of just over 19,000 feet, which is close to about 6,000 meters including a horizontal ridge of almost 10,000 feet. And this well is expected to have 28 fracture intervals when completed. Our optimization and efficiency work has continued to provide excellent results in the Montney, where we typically drill our horizontal well to about 14,500 feet total measured depth, with 10 fracture stages per well. However, like the Horn River, we recently drilled our well to a total measured depth of greater than 19,500 feet that will be stimulated with 14 fracture treatments. We are seeing typical 48-hour initial production rates in this area of about 13 MMcfe, and a well history that is showing a recovery rate of roughly 0.65 Bcf per fracture interval. When you consider that we brought our drilling and completion costs, sort of our all-in cost, down to approximately $560,000 per interval, that's a decrease of almost 60% since 2006. These wells offer some of our highest rates of return in our company's portfolio. We've been running about 11 rigs in the Deep Basin and we plan to continue to run about that amount for the balance of the year. Our Deep Basin asset, especially within the Bighorn play are liquid rich. At Bighorn for example, we're seeing about 15 to 20 barrels of condensate or C5 plus per MMcf of gas on average. This boost the value of our production because condensate prices track relatively close to WTI [West Texas Intermediate]. We plan to continue pursuing liquid-rich opportunities across our portfolio. The liquids-rich component of our Canadian asset combined with our favorable royalty framework within the Alberta and British Columbia have gone a long way to support the competitiveness of our Canadian asset. Randy?

I'll now turn over to Jeff Wojahn to talk about our U.S.A. division results.

Thank you, Randy. In the U.S.A. division, production volumes averaged just over 1.9 Bcfe/d for the quarter, a 17% increase over the second quarter of 2009, led by strong growth in the Piceance Basin, East Texas and the Haynesville shale. Quarter-over-quarter, U.S.A. division 2010 volumes were down 4% as a result of the sale of production affiliated with non-core assets at Wonsuther [ph] and the Paradox Basin. We've had some excellent results so far this year in the Piceance Basin. Second quarter 2010 average production was 470 MMcfe/d, about 29% higher than at this time last year. Our capacity reduced production from 2009 came back online better than expected, and many of the Piceance wells that we've recently completed are performing above expectations. As a result, we have increased our 2010 average production guidance by 40 MMcfe/d. In the Haynesville shale, which we will now be reporting as a separate key resource play, we continued work on our land retention strategy, drilling a total of 41 net wells in the first half of this year. 2010 second quarter Haynesville production was just below 270 MMcfe/d, net to EnCana. Putting us on track to meet our year end average production guidance of 325 MMcfe/d and exiting the year at greater than 500 MMcfe/d. In addition to our land retention strategy, we now have one gas factory pilot plant in the DeSoto Parish of Louisiana, that was the eight wells drilled from a single pad. With careful and continual optimization, we believe that when we are operating at full-gas factory mode, we can achieve substantial reduction in our drilling completion tie-in and operating costs. During the second quarter, we drilled a promising well in the new Brent Miller field, a sizable Texas extension in Sabine County. This well extended the Haynesville and Mid-Bossier potential into an area where EnCana holds 45,000 net acres. Our well initially flowed at 25 MMcfe/d but when a second wing valve was added, production from the 14,500-foot depth well increased to 32 MMcfe/d. We have a second well drilled and waiting completion in late July. In the U.S.A. division, inflationary pressures from most of our contracted services and materials remained in check, with the exception of pumping services, where we've experienced some price increases this year. We do see some pricing pressure looking into 2011. In areas where activity continues to be intense, such as the Haynesville shale and the Southern Rockies area, competition for completion services has risen. With completion costs now representing around 40% of the all-in capital cost per well, we are monitoring this expense very closely and are actively looking at innovative ways to manage our completion costs. This includes the development of fit-for-purpose skid mounted completion equipment and the potential development of long-term partnership arrangements with our service providers. I will now turn the call over to Sherri Brillon, who will discuss our overall financial performance for the quarter.

Thanks, Jeff, and good morning. EnCana delivered solid results for the second quarter and first six months of 2010. Production volumes were strong, average natural gas prices before realized hedging were up, and operating and administrative costs came in below guidance. On par with the first quarter this year, second quarter cash flow was approximately $1.2 billion or $1.65 per common share diluted. For the six months ended June 30, 2010, cash flow was approximately $2.4 billion or $3.22 per common share diluted. Both of these 2010 figures represent about a 15% year-over-year decrease when compared to 2009 pro forma results. EnCana's 2010 cash flow has been adversely affected by lower realized hedging gains. Compared to the same period of 2009, realized after-tax financial hedging gains in 2010 were down $423 million in the quarter and $839 million in the six months. It's important to note that EnCana continues to reap substantial benefits from its hedging program for 2010. For the three and six months ended June 30, realized after-tax commodity hedging gains were approximately $263 million and $388 million, respectively. For the balance of the year, we have just under 1.9 Bcf/d of expected production going forward at an average price of $6.05 per Mcf, considerably higher than current market prices. EnCana's hedging practices are critical component of our business strategy. Our commodity and other risk management activity provide increased certainty to our cash flow and that, in turn, helps ensure the stability of our capital program, long-term planning and dividend payment. Importantly, EnCana's hedging arrangement are with a diversified group of approximately 20 different counter parties, all with strong investment-grade ratings. We've increased our 2011 hedge position slightly, and we have now approximately 1.2 Bcf/d of expected production hedged at about $6.33 per Mcf for the year. Our…

All right, thank you, Sherri. Year-to-date, our average NYMEX natural gas prices have been just under $4.70 per MMBtu. This commodity price is stronger than we were seeing on average at this time last year. We do not believe that it's representative of the current marginal supply cost required to balance markets in North America. We believe that price is likely closer to $6. Today, the forward curve is showing future natural gas prices in the range of $5 to $6 per Mcf for some time to come. And since we run our business for the long term, we believe our best strategy is to achieve the highest growth we can at the lowest cost we can achieve. EnCana has always been focused on being a low-cost producer, and year-to-date costs have been below guidance. We believe and want to ensure that this trend will continue. At the beginning of 2010, we will look that our portfolio of incremental development opportunities. EnCana's overall corporate supply costs, that is the flat NYMEX price required to provide a 9% after-tax return was about $4 per Mcfe. I'm very happy to report that thanks to our team's dedicated and continued optimization and efficiency efforts, EnCana's portfolio of assets currently have an average supply cost closer to $3.85 per Mcf. And we see many reasons we should continue to see the supply cost coming down over time on an inflation-adjusted basis. During the second quarter, EnCana announced that it signed Heads of Agreement memorandum with China National Petroleum Corporation or CNPC, to discuss potential joint venture activities within our Canadian division holdings, specifically in Greater Sierra including parts of the Horn River and the Montney formation and Cutbank Ridge. I'm unable to say much at this time, but I can say that our discussions have been developing very well. And if successful, we foresee a significant multiyear transaction that can help provide us with the ability to grow at a faster rate and a lower cost. The breadth and depth of EnCana's existing portfolio of assets means that our current development pace of approximately 1,300 wells per year, we would anticipate drilling wells for more than 18 years to come to access all of our best investment opportunities inherent in our lands currently. This, we believe is simply too long for our shareholders to wait to access that value. Our joint venture activity, which has brought us approximately $4 billion in capital investment over the past three years is an important part of how we conduct business. Not only does it accelerate our development timeline, but allows us to focus on that development in highly efficient and cost-effective manner. We've got a solid first half of the year, both operationally and financially. As we move ahead in 2010, we look forward to both the challenges and the opportunities that the year will bring. Thank you for joining us today, and our teams are now ready to take your questions.

[Operator Instructions] Your first question comes from the line of Andrew Fairbanks from Bank of America.

I had a question for Mike at Bighorn, it looks like you're taking the program up by about 20 wells. And I was just curious why the areas or play types was getting the incremental capital on that unit?

Yes, Andrew. Mike here with the Canadian division. We have been pretty active in Bighorn, it's essentially the Alberta part of the Deep Basin. You may have seen Alberta actually changed some of their royalties and made them a little bit more favorable within Alberta on the crown land. We have actually increased our program there. We're going essentially from about 30 wells, now up to about 50 wells. Volume, we predict will increase from about 205 for the year to about 230, and we have been drilling some horizontal well out there in the Cretaceous stack, like a lot of the operators are. And we're seeing some pretty good results on that, so hopefully we'll have more to come on the next couple of quarters, from some of the development there.

Your next question comes from the line of Greg Pardy from RBC Capital Markets.

Randy, could you remind us just what your natural decline rate is now, and what maintenance CapEx would be to hold production flat?

I think the last update that I had for the natural decline rate was around 21%, does that sound about right? And the last number I had was about $2.5 billion to keep production flat.

Just around the operating cost numbers, I mean you've dropped it once. Is there a sense, I mean, if your supply costs are going down, would you expect further improvements in your unit OpEx going into 2011?

We're going to see and this is all going to be done on an inflation-adjusted basis because there may be inflation that creeps back into the industry. But as we start getting into the bigger gas factories, we definitely will see that our op [operating] costs will come down further.

Mike, the 28 fracs you referred to, just in the Horn, is this anomalous for you in terms of drilling a well like that, or is this possible that this could be become more of the norm?

Well, I can tell you, Greg, we're going essentially from 1,000 meters to 2,000, now even up to 3,000 meters on the horizontal. And so we keep increasing it, so I think it will probably become sort of more of the norm, if you will. Our frac basin is essentially maybe about 150 meters, maybe a little bit more than that, so we can put a tremendous amount of fracs on those rigs on horizontal wells. Essentially now in the Horn River, we may develop as much as, say, five sections or five square miles off one single well site, if you will. So it very much reduces our environmental footprint. We're finding we can drill these wells relatively quickly and completions has kind of been the limiting factor on length. So right now, we continue to drill longer and putting more frac, so I would think that will be more of the norm.

Do you have the IP on that well?

We don't actually have the IP on that well. That is one of the wells that EnCana's operating in our 63-K pad and that pad -- essentially, we're drilling about 16 wells per pad and we may put as many as 20 to even 28 fracs per well. So that pad will start coming around the 10 million, would be the IP rate out of those wells.

You're not talking too much about Panuke these days. Is it -- are we looking at the back half of 2011?

Yes, we kind of updated that a little bit, last quarter we talked somewhat on Panuke. Yes, it is essentially the second half of 2011. Things are on track there. Essentially, we've done now where we re-completed two wells, we're on our third out four wells that we've drilled our disposal well there. The pipeline to shore is complete, and we're going to do our infield gathering system this summer, so essentially all we need is the production field center to come out of the Middle East, and we'll hook that up next year and we're ready to go.

Your next question comes from the line of Mark Polak from Scotia Capital.

Just wondering if you could provide more color on where that additional $500 million of capital is going, and it sounded like it's kind of related to the increase in production guidance for this year, just wanting to confirm that.

Mark, largely this will relate to getting production growth enhanced for 2011 and building up to the larger the capital spend that we anticipated with our plan to double production over the next five years. Part of it is going into a gas factory in Haynesville, the eight well gas factory that Jeff Wojahn spoke of. And, Mike, yours is going a little bit to Horn River?

Yes, not so much. We're doing more on the Jean Marie and more on the Montney. Essentially, level loading our programs for the remainder of the year.

Your next question comes from the line of Mark Gilman from The Benchmark Company.

Jeff Wojahn, I wonder if you could talk just a little bit, we haven't really discussed much about the Deep Bossier lately. Production seems to be slipping a little bit and activity levels also seem to be pretty subdued. Give us a little bit of an update on that play.

Sure, Mark. The big issue is that we're ramping up our lease retention program in the Haynesville. We have 26 operated rigs working on the Haynesville play, and we've moved a number of our rigs from East Texas to the land retention program in the Haynesville. Coming into the year, we have very strong results in East Texas, and our programming is reflected in record Q1 volumes. Subsequent to that, we've moved to a steady five- to six-rig program in East Texas and moved four or five of our rigs and some of our completion activities, again, just across the border into Louisiana. So it's not really a function of what we're doing in East Texas. It's more about the land retention strategy in the Haynesville and making sure that we complete that 250 well, 100 wells this year program, and then 100 wells more in 2011.

I got one for Mike Graham, if I could. I noticed with respect to the resource play guidance that activity levels and capital expenditures are a bit higher than what we're looking at before on Coalbed Methane, Cutbank, Greater Sierra. Both activity levels and spending up on each of those three plays yet no change in the production guidance on any of them for the full year 2010, Mike. What's the thought there?

Yes, I can talk a little bit to that. But essentially, these plays were essentially -- we're load leveling our programs for the second half of the year. You may have seen, we did have a relatively slow start within the Canadian division. In Q1, we did about 1,250,000,000 cubic feet a day. And in Q2, we're about 1,400,000,000. So we're up about 150 million a day quarter-over-quarter, but we did have sort of a program where we kind of reduced some of our completion efforts in 2009, did a lot of that Q1 2010. So our volume is actually ramping up quite a bit. We're doing about 1,450,000,000 today, and we expect that to close to 1.5 Bcf equivalent per day out of the Canadian division. But typically, within the Jean Marie or Greater Sierra, we plan to drill a few more wells in the second half, had to load level that program. Because of our Coal Gas joint venture, we have to spend a little bit more capital there. We are drilling wells now on the Coal Gas joint venture, but we put the infrastructure capital to 50/50. Cutbank, we're getting tremendous results in the Montney. And we did have problems. We talked about it sort of Q1 into some sort of unscheduled maintenance within Cutbank. But like I say, it's ramping up very nicely. You'll see quarter-over-quarter, flows for our resource plays are up. We've had tremendous results. We talked a little bit about it in the Bighorn within the Deep Basin, some of the horizontals within the Cretaceous back. And right around Central Alberta and Southern Alberta, we've had tremendous wet weather, if you will. If you watch the Calgary Stampede on TV, you would've seen it. But it has slowed us down a bit on our [indiscernible]. So we're hoping to kind of catch up there and maybe be a little bit more active in the second half.

Mike, are you doing anything with dual laterals in the Montney, given upper and lower potential, as well as other possible horizons there?

We are looking that. We have done some sort of in the past. Now Mark, essentially, what we're doing is drilling longer lateral, if you will. Like I say, we're getting now to 3,000 meters on the lateral in some of these wells. But we are looking at dual laterals or maybe put sort of horizontals one above the other, if you will. We essentially stagger in the Horn River these 50 meters on a vertical depth, just so we can access all of the resource. So we are looking at a lot of different initiatives.

And Mark, our work to date would suggest until we sort of exhaust the technology on getting longer and longer reach wells, we seem to be getting a much better economic benefit there. Once that's done, then I think our focus would be on multi-laterals, whether they'd be vertical or side-by-side.

Yes, Mark. We do have lot of multilaterals in the Jean Marie. We've done quite a bit in the Cadomin well, where you don't have to worry about frac-ing them. We can drill them that way, but the problem is just -- we do have some problems around completion technology on the multilateral, so that's what we're working on.

Last one for me is this DD&A issue, which I guess I continue to find to be troubling. I mean not only is it not going down, it seems on a unit basis to be rising. It prompts me to ask you. What percentage roughly of your resource play production currently is reflective of the gas factory approach as opposed to something that would be of a somewhat less efficient nature?

We're just beginning the gas factory approach. The gas factory is starting to be developed in the Montney formation, I guess, last year. So we've been getting to bigger and bigger pads. But as production is really low at this point in time, the Horn River will be developed immediately with the gas factory approach. We're not able to get there yet, significantly in the Haynesville, until all the land retention issues are completed. But that will be, as we said, we're starting one of them this year. Certain parts of the Piceance Basin, we have been developing that way for a while now. But we're just really, like I say, scratching the surface of the design, and ultimately, all of the changes we'll ultimately get. We do forecast though our finding and development costs. Even this year, we'll start coming down fairly significantly, certainly on a technical basis. And in years to come, they could go down even further. So we're targeting numbers that are getting down to a range of about $1.50 and below versus our DD&A range, which is somewhere around $2.60 or so. To have a significant impact on the DD&A, we have to have an awful lot of changeover, I guess, of the overall inventory of the company with having -- it would take a few years to have a significant impact on DD&A.

Your next question comes from the line of Bob Morris from Citigroup.

Randy, I noted that you've brought down your corporate-wide supply cost from $4 to $3.85. Really I have two questions here. One, if it weren't for the need to hold the acreage in the Haynesville, would the activity level be just as high? Or would you scale that back?

I think we'd probably have just as high in activity level, but we'd probably be getting better results because we'd be able to concentrate our activity in places like the Haynesville into the gas factories.

So it would be economic even without the need to hold acreage at either the $3.85 or at current prices, more so, $4.50.

Yes, we believe so.

Then it leads to my second question because we're getting similar comments across the industry as far as people bringing down their supply cost and seeing these efficiency and cost improvements across the board in these shale plays. And clearly, the only people putting rates to work just to hold the acreage are doing so in these shale plays, which have very low supply cost. So I'm just curious, I see your comment that the marginal supply of $6, given that you also pointed out in your Analyst Day presentation, you think industry-wide supply will continue to sharply outpace demand growth. And so with the running room in these shale plays and given that's where the activity's focused, and even when it's not in the shale plays, it's apparently economic in today's price levels for the rigs that are running, how is it that you ultimately get to the conclusion that $6 is the marginal supply? In other words, what gets us there if we've got so much running room where supply-cost levels are in these shale plays today?

Well, there's a couple of things. Not all of the production in North America is coming from these plays. We've done and have done for many, many years extensive modeling of all the wells in North America and all the basins in North America. And it's from those studies that we determine what we believe is required to balance the markets. Now of course, that's based on our internal assumptions of demand side growth. There is, of course, an air bar in that. It's not an absolutely accurate calculation when we get down to it, and we usually express it within plus or minus $0.50 off of a number.

So I guess my follow-on question would be that, if some point, you believe that the growth in supply from all these shale plays that we're seeing here does not keep up with demand growth, where is it then that the drilling goes to or the supply comes from that needs $6 gas to be economic, if it's not in the drill today?

Yes, and of course, we're talking about other people because we've already said what our supply cost is. We've modeled our growth objective, the doubling of the company on a per share basis over the next five years, and we find that it is achievable down to about a $5 North American natural gas price. So on a combination between our hedging activity and realized prices, we're in or above that range today. So for us, we're fine. I'm not sure that everybody has supply cost that are that low.

Your next question comes from the line of Brian Singer from Goldman Sachs.

At the end of your opening comments, Randy, you mentioned that your 18-year inventory, it was probably a little bit too long. And I wondered, in the context of bringing in a potential joint venture partner in Canada, do you think about accelerating activity beyond the types of numbers that you put out already? Or would you use the proceeds or carries from a joint venture more towards improving the balance sheet than maintaining your levels of activity and stated growth objectives?

I think that's going to be a dynamic question, and it's probably something we're going to be answering every year as we put our capital programs together and as we look at the current natural gas price and the environment. It could do either. So we could either achieve the objective at a lower cost or we could increase the overall objective. What I'm pretty certain about today is that over the course of the next couple of years, that inventory will increase a result of the kinds of activities that have made it increase so dramatically over the last number of years.

Did I detect that there's some price sensitivity in terms of making that decision? And can you provide any parameters around where that might be in terms of whether it'd be a future strip or whether in fact, I guess, prices of the day do you get to a $6 as you talked about earlier?

It is a little tough to answer that question precisely right now. It maybe be a little bit easier if we're able to achieve the major farm-out by the end of this year. I understand exactly what the implications of that are. We'll have a better view of prices and costs, Brian.

And I guess the last question for Jeff, you mentioned the Brent Miller well. Can you just put that into context relative to the Haynesville in terms of potential acreage depth and how large a play and whether you have to prioritize that or the Haynesville, Bossier or Brent Miller or whether you could be doing any or all of them at once?

We're thinking about the ramifications of it. There were kind of ramifications with the Brent Miller field. First of all, it was the deepest Haynesville or mid-Bossier successful commercial well that we have drilled, moving to that 14,500-foot vertical depth. And to be able to drill it at high-pressure, high-temperature environment is a technology milestone for our teams. And we have exposure to that, not only in the Louisiana side, but as we mentioned, we have 45,000 net acres on the Texas side that we think we have proved up with this well. Not only proved up from a geological point of view but from a technology point of view. So those are big milestones for us that give us increased confidence. Secondly, the well performed as well as any well that we have seen in the Haynesville to date, so we were able to demonstrate high reservoir quality at depth and in the extension of the play. So another large vote of confidence for our overall land base which we now have even increased confidence by this extension. Thirdly, in Texas, the ability to drill longer wells is easier. In Louisiana, we're currently working on regulatory reforms that allows us to drill wells outside of a one-square mile area. In Texas, you can put units together that will allow you to drill 5,000 foot or even potentially longer laterals, meaning that we can mimic the results that Mike talked about in the Horn River or the Montney group. So I think the Brent Miller discovery is very significant. It increases our overall confidence of our overall land base. But more than that, it gives us flexibility in regards to moving technology and flexibility relative to regulatory issues, both in Texas and Louisiana.

Your next question comes from the line of Chris Steele (sic) [Chris Feltin] from Macquarie Securities.

Just with respect to hedging, it looks like EnCana layered in some hedges below $6 in the second quarter. As you see EnCana's supply costs coming down, does your threshold on hedged gas prices come down with it?

Fortunately and unfortunately, yes. It's more of our view of what longer-term prices might be, and our view in longer-term prices has been coming down as we see more and more shale gas plays come on the market, particularly those ones that are liquid rich, which will come on despite what natural gas prices are.

I mean this is tied back to your previous comment that your model works at $5. That model, I guess, that gets you on the 15% compound annual growth rate. Is that looking at it in the context of it's self funding in terms of you generate sufficient cash to grow at that level at $5? Is that the way to interpret that?

Well, not exactly. It's within our debt metric ranges that we've had well established. And I believe, in our modeling, we're able to maintain our dividend at the current rates, and we're also able to keep our debt to capitalization significantly below 40%.

And just the last one Randy is, buybacks have been consistent in the first two quarters of the year. Should we expect that through the balance of this year?

What you should expect us to do, and this is really where the per-share nature of our growth strategy comes into play, and so it's a good question. And one for me to highlight is, whenever we sell a cash flow-generating asset, our anticipation is that we would use that revenue received to buy back shares. And so far this year, we've made a number of divestitures. We've estimated that the cash flow generating divestitures that we will make this year, net of acquisitions, would be in the range of about $500 million. That was what we estimated at the beginning of the year. That's what we have effectively bought back so far this year. So our plans right now are not to do anything additional unless, of course, we sell some additional cash flow-generating assets. And those could be either midstream-type assets that we have typically sold when we view that others view the value of those assets to be higher than ourselves.

Your next question comes from the line of George Toriola from UBS.

The first is just looking at capital efficiency and the number of fracs per well that you think you can ultimately achieve. I just wonder if there is a difference that -- so it's a two-part question. First, I wonder if there's a difference between, obviously, the longer you reach and the more you open up the horizon, you can book more reserves and that sort of thing. But just from the economics point of view, when do you get to a point where things like back pressure or interference start to cause diminishing returns on your frac program there?

George, we've been monitoring this for quite some time and have fully expected. What you anticipate is that there will be at some point a significant diminishing returns based on going to longer lengths and additional fracs. The facts have not borne on that. And what we find is we're able to technologically achieve some pretty long lengths and it's often other factors such as lease boundaries that have set the length of the well versus what we can achieve technically. No we have on some occasions also achieved technical limits to our length, but it's not a matter of necessarily diminishing returns. It's just the limit of the technology.

And then secondly, on the Collingwood shale, the exploration well you drilled there, I wonder if you can provide a bit more color in terms of how many fracs and maybe some properties that you see organic content sort of permeability, things like that, that would help also understand the potential of that play a little bit better.

I'll let Jeff answer it. But you know what, we're in a land capture mode in the play, and so it would not be a normal practice to release any more information than you need to release to meet the regulatory requirements.

George, it's Jeff Wojahn. Michigan is a play that we, through our new ventures group, have been working on for many years in an incubation phase. And we announced after the last Michigan State sale that we had previously acquired 250,000 net acres in the position. We had drilled a well, the first well that we are aware of, a horizontal well in the Collingwood shale in Michigan. That well was sub-commercial relative, but it did prove up to us that there is hydrocarbons in the system and liquids in the system from a hydrocarbon point of view. From a technical point of view, we saw a lot of things that we were hoping to see. So that was positive. The negative is that the costs were too high and the tight crew from the well was not sufficient for a commercial development. One well doesn't mean a lot in these plays. So that's kind of where we are. The news on the play, as Randy had stated, is that there is another state landfill coming up. And so for that reason, I don't think you'll see EnCana really talking in details about the play beyond what we've already released. That sale is coming up in October. So maybe at end of October, we'll comment again on where we are on the play. Because of competitive reasons, we're not going to further comment on the play.

And at this time, we will go to questions from the media. Your first question comes from the line of Amanda Fraser from Allnovascotia.com.

I was wondering if you could help me where the deep enough project is in terms of the budget.

I did talk a little bit earlier on it maybe something like that. We are moving along pretty good. We said we're going to talk a little bit more about our capital. I think the last numbers we've said was about $800 million sort of for the project. Our wells are taking a little bit longer. We've gone 39 to like 50 days for some of these recompletion. We are on our third out of our four recompleted but essentially, we only have to recomplete the two wells. And at that time, we'll have a better idea on our costs. But there has been, like a day, there has been some pressure on our costs. Maybe in the 10% to 20%-type range, and that is from weather, one. The rig at the harbor [ph] quite awhile in the East Coast, and two, to do with FX as well and kind of a strengthening of the Canadian dollar. So costs aren't too bad, a little creep on them and schedule is on track. Like we said now, middle of this 2011 will be up and running. We're going to bring it on at about 200 million cubic feet a day. We will have capacity of about 300 million cubic feet per day. And I could tell you, the two wells, we were very pleased on the rates out of those wells when we casted them. But these are very strong wells at 50 to 100 million cubic feet per day well, and we look forward to coming on in the middle of 2011.

What about in terms of the Production Field Centre? Where is that relative to construction?

Production Field Centre is being built in the Middle East. That's kind of where the delays are. The delays are not on the EnCana side, it really is delays from the construction in the Production Field Centre. It is really a lease for us, so we're not responsible for the capital. And the large capital portion was drilling and recompleting the well. The pipeline is shore, which is now complete, and hooking up the Production Field Centre. So you may want to talk to Single Buoy Moorings, a company who is actually dealing with the Production Field Centre on the call further on [ph].

Do know when it's going to arrive though?

We're hoping it's going to arrive in Q1 2011 and we'll have it hooked up and ready to go sort of by middle of 2011.

Your next question comes from the line of Dan Healing from The Calgary Herald.

I was just wondering to see if you have any comment at all on the deal with Apache buying those BP gas assets. Given EnCana's relationship with Apache in the Horn River, does this create opportunities for the company?

I don't think we can make any comment on that. We don't really know that much about the deal or what might arise out of it.

I was also going to ask the $500 million increase in capital spending. Can you give me an indication of how that's going to be split between Canada and the U.S.?

Sherri, do you have the numbers? $300 million in Canada and $200 million in the U.S.

Is EnCana looking at the Duvernay shale play in Alberta at this time?

Yes, we can't comment on any exploratory plays.

At this time, we have completed the question-and-answer session and will now turn the call back over to Mr. McRitchie.

Thank you, everyone, for joining us today to review EnCana's second quarter results. Our conference call is now complete.