Good day, ladies and gentlemen, and thank you for standing by. Welcome to the EnCana Corporation second quarter 2009 financial and operating results. (Operator Instructions) I would now like to turn the conference over to Paul Gagne, Vice President of Investor Relations. Please go ahead, Mr. Gagne.

Thank you, Operator, and welcome, everyone, to our discussion of EnCana's second quarter 2009 results. Earlier this morning we updated our 2009 guidance document and Key Resource Play information sheets. In addition, we posted a supplemental slide package providing the highlights of today's conference call. These materials can be found in the Investor Relations section of our company website, EnCana.com. 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 One of EnCana’s annual information form dated February 20, 2009, 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 amounts are reported on an after-royalties basis. Accordingly, any reference to dollars, reserves or production information in this call will be in U.S. dollars and U.S. protocols, unless otherwise noted. Randy Eresman will start off with highlights of our operating results and then turn the call over to Brian Ferguson, EnCana’s CFO, who will discuss EnCana’s financial performance. Following some closing comments from Randy, our leadership team will be then ready for questions. I will now turn the call over to Randy Eresman, President and CEO.

Thank you Paul, and thank you, everyone, for joining us today. Today’s call will highlight our performance in the second quarter of 2009. We're now at the midpoint of the year and we're very pleased with our results to date. Our performance is the result of many years of hard work by our teams and demonstrates the advantages associated with our resource play strategy. We've established premium land positions in many of the major North American unconventional gas fields and we hold recognized top-tier oil properties as well. Despite the current lower commodity price environment, our determined focus on costs further distinguishes us from our competitors. Our quarterly natural gas production was on target. This was achieved through lower than expected royalties on our Canadian production offset by volumes we chose not to bring online in both Canada and the United States. Our production would have been quite a bit higher than our guidance had we not restricted volumes by about 300 to 400 million cubic feet per day. About half of this volume could be brought on relatively quickly as it is physically shut-in, while the remainder would take more time as some additional work would be required to bring it onstream. We’ve updated our guidance document to widen the production range to reflect the uncertainty of the current commodity price environment. We’ve also updated our capital and operating costs. While we're spending more time scrutinizing how we manage our existing production base, we continue to move forward with the evaluation of our emerging plays. In the Haynesville, we continue to increase our drilling program and the latest well results continue to be very positive. We plan to drill about 50 net wells this year, which will enable us to further increase our understanding of the play, evaluate our…

Thanks, Randy. Good morning, everyone. EnCana had another strong quarter financially. Despite a 68% decline in NYMEX gas prices and a 52% drop in WTI, we achieved cash flow per share diluted of $2.87, down 25% compared to the same quarter of 2008. Our cash flow performance is within expectations and, as a result, we have maintained our full year cash flow guidance at between $9.50 to $11 per share. Our cash flow performance was accompanied by strong operating earnings of $1.22 per share diluted, down 38% year-over-year. Our net earnings for the quarter of $0.32 per share were down 80%. This included realized after-tax hedging gains of $900 million in the quarter which were primarily offset by $750 million of unrealized after-tax hedging gains (sic) in the second quarter. The unrealized hedging losses are a result of marked-to-market accounting, which causes us to book gains or losses to net earnings in prior quarters and then remove the prior gains or losses when they are realized as we get the cash proceeds. Year-to-date we've realized after-tax hedging gains of $1.6 billion. We also have in place a strong hedge position for the balance of 2009 and into 2010. This will greatly reduce volatility in our cash flow. Both cash flow and operating earnings beat the Street estimates. Looking specifically at our costs in the second quarter, combined operating and admin costs were $1.15 per thousand cubic feet equivalent and below our previous full year guidance estimate of $1.40. Decreased costs were primarily due to lower long-term compensation costs, a lower U.S.-Canadian dollar exchange rate, and lower repairs, maintenance and workovers. As Randy mentioned earlier, we adjusted our 2009 guidance. We've lowered our full year estimate for our operating and admin costs to $1.30 per thousand cubic feet equivalent. Our balance…

Thank you, Brian. So far our non-commodity based results have been positive and in line or better than our expectations, a credit to our teams, our assets and our strategy. We continue to use our advantage of being a company with a strong diversified portfolio of low-risk, low-cost, long-life development projects. We're focused on optimizing the factors that are within our control and minimizing our exposure and risk for those that are not. We strongly believe that we have premium a position in the two energy sources which hold huge growth potential in North America - unconventional natural gas and enhanced oil. We believe that there are enormous economic and environmental advantages to expanding the use of natural gas in our economy and that future sources of domestic oil will need to be extracted using enhanced recovery methods with a lower impact on the environment. We continue to keep our operations steady and consistent through this low point in commodity pricing and uncertain economic environment. However, this market allows us to showcase the strength of our business model to our shareholders, demonstrating that we can successfully withstand the most difficult economic conditions in recent memory. Finally, I'll now take a moment to provide an update on the timing of the proposed corporate reorganization of EnCana into two independent energy companies. We continue to believe that the underlying reasons for creating the integrated oil company Cenovus and establishing EnCana as a pure play natural gas company remain intact; however, significant uncertainty in the current economic environment continues to exist. We remain committed to maximizing value creation for our shareholders and will provide updates in the future as appropriate. Thank you for joining us today. Our team is now ready to take your questions.

(Operator Instructions) Your first question comes from Brian Singer - Goldman Sachs.

When you think about your lower long-term gas forecast of $6 to $7 combined with the improved productivity from the Horn River and Montney plays, how do you think about your own Canadian production growth in that environment as well as Canadian production, gas production, growth overall?

Corporately we've been targeting a long-term production growth for natural gas in the 4% to 6% range, the target we've had for the last number of years, and then, of course, as you know, in this environment we've slowed it down a bit. In that environment we have a lot of plays such as our Montney, a lot of our Shell gas plays that have much lower supply costs than the bottom end of that range and can do potentially quite well. In the meantime and over the last couple of years we've been continually divesting of some of our more mature conventional assets that possibly won't be able to compete as well in that long-term environment. So I think we're in pretty good shape to at least maintain that same target and I'm saying overall for the company, not specifically Canada or the United States, with the possibility that it could actually rise in the future as a result of having a more concentrated base in these lower-cost plays.

And do you see Canadian production overall as less competitive relative to the U.S. either within your own portfolio or, more likely, overall?

You know, it really is a play specific situation. There are and have been certain challenges historically being in Canada with a higher overall cost structure and challenges oftentimes with changes, rapid changes in exchange rates and the access to supplies and services. That situation has largely been reduced right now and we're seeing significant opportunities arise in Western Canada. The royalty structure of the Alberta government works in our favor today, so there are plays that are actually becoming more competitive compared to the U.S. Generally, wherever you have the most concentrated resources and the lowest cost development, lowest operating cost, those are the ones that are going to be developed first in the future in this kind of a dynamic environment.

And lastly, could you provide some more color on the production that's either shut-in or uncompleted, the 300 to 400 million, of the half of it that you mentioned takes a little bit of time to come back on, at what price and how long would it take to bring back? And maybe if you could provide a U.S.-Canada split of that 300 to 400 million?

The majority of it is in the U.S. and Jeff can actually go through where the bigger chunks of gas are either shut-in or have not been brought on and the details around that.

In regards to the U.S., we have approximately 200 million a day shut in or curtailed and you can see when you look at our guidance relative to our KRPs or Key Resource Plays in the U.S. that you've seen a reduction from Q1 to Q2. Those reductions are related to those shut-ins or curtailments that I mentioned, the 200 million a day. In regards to overall, when wells are shut-in or curtailed outside of swabbing operations and that's just a function of equipment and timing, we can bring on our wells fairly quickly. For instance, in East Texas, because of the high pressure environment we're talking about weeks. In the case where swabbing operations are required or in the case where fracture stimulation operations are required - and that's beyond the shut-in or curtailed volumes that I mentioned we're talking, you know, four week to six week timeframes.

And Mike Graham also has some shut-in in the Foothills division.

Yes, but we've actually got, in the order of a little over 100 million cubic feet a day shut-in in the Canadian Foothills division right now and a lot of that is in the deep basin, a lot of it's in the Montney, places where we're 100% and there's no issues around royalties or the like.

Your next question comes from [Brian Lavely] - Tudor, Pickering, Holt & Co. Brian Lavely - Tudor, Pickering, Holt & Co.: I just really have a follow up question on your restricted production. Can you give a comment on just that number or the backlog of wells that you actually have that are drilled but not completed?

I don't know that we've been tracking that in inventory because we always have a lot of wells that have been drilled and not completed just sequenced in. But we have definitely in some areas slowed it down a bit. But I don't think we have been tracking that specifically. Brian Lavely - Tudor, Pickering, Holt & Co.: Then going on to your second quarter production, first is your full year guidance and you've already kind of alluded to that. Can you just kind of comment a little on how you think about that strategy of continuing to drill but not complete wells going forward and how that may play out for the rest of the year? Because it seems like if you look at that comparison between the second quarter and full year, it seems like that there is some production coming back to the market in, say, the Jonah and East Texas areas.

You know, the natural gas market has always been volatile and always been surprising for us, so we'll wait for opportunities to bring on wells that have high initial natural decline. Wells that are just going to slow down we can turn them on and react to the market very quickly as well. I guess we really don't know what's going to happen in the course of the next year, but I would not want them to be shut-in indefinitely. Brian Lavely - Tudor, Pickering, Holt & Co.: Sure. So in your full year estimates then you have dialed in some curtailment in those numbers?

In our full year estimate what we've done is we've simply given a wider range for the potential outcome this year. And if the market did come back on the fall we'd be able to bring production back on to our original target and possibly even exceed it. If [the fall] market is quite low, which it kind of looks like it will be today, it's more likely we'll hit the lower end of that range. Again, it's a pretty dynamic situation. We're seeing prices in some of our basins that have gotten pretty low. Brian Lavely - Tudor, Pickering, Holt & Co.: And kind of along with that have you seen some improvement or to what extent have you seen improvement in the realization from the Rockies area?

Well, I think the basis differential in the Rockies has shrunk quite a bit, so that's been helpful since last year. What other comments can you make about that, Jeff?

Yes, you know, I think one of the things that we saw earlier in the year is a dramatic decrease in rigs in the Rockies and with that there's a delayed reaction in regards to production drops. And we see some of the future fundamentals of the Rockies suggesting pricing in that 80% to 85% range of NYMEX. That begins to equalize the Rockies relative to potential other basins where we can continue. But overall I would say the fundamentals in the Rockies are weak but improving.

Yes. I think the basis for companies [inaudible] the last quarter came down to about $0.66 and I know in periods in the past that was getting closer to $1, so overall it's come in with the reduced production.

Your next question comes from Chris Theal - Tristone Capital.

In the press release you guys talk about the increase in Haynesville IP rates moving up to 14 intervals per well. Can you just give us sort of a barometer? What did IP rates look like on the first sort of vintage of wells relative to the IPs you're seeing on these increased frac densities?

We started out in the Haynesville three years ago drilling vertical wells with 1 million a day IPs or less and we have steadily increased IPs through the application of horizontal drilling, an increased in sand concentrations, water concentrations, length of wells and stages, and you know, today we're moving from eighth-stage wells to 12 to 14-stage wells. And with that what we're seeing - you know, that's about 3.5 million pounds of sand in those 12 to 14-stage wells - with that we're seeing water production profiles, higher pressures and higher rates. So we have talked about a 6 Bcf-type curve and that really was based on kind of an 8-stage well, 3,000-foot lateral, and we're wondering if with time we can gravitate towards an upside of a 9 Bcf-type curve with 12 to 14 stages. We have limited data today - three or four wells that EnCana has - but those wells are very encouraging and have been at the top of our ranges. In fact, one well we drilled this last quarter, the Conway Harris 22 well, we actually physically flowed at over 20 million a day at 8,400 pounds flowing pressure and that was a higher-stage well with more [profit] in the core area of Red River where we've seen high rates before as well. But it's an indication that more stages, more sand, more emphasis in our fracture stimulation program will yield higher results, and so we're moving that way in the play.

Any incremental thoughts on Mid-Bossier since the Q2 call?

We're currently pumping a well as we speak in the Mid-Bossier. I don't have specific results and I anticipate that there'll be some more results and comments in the Q3.

Your next question comes from Brian Dutton - Credit Suisse.

Lots of commentary's been coming in lately on the Kitimat LNG project and I was wondering what your thoughts are there in terms of the possibility of you being a supplier to that project?

The Kitimat project has always been of interest to us. In fact, I think we stimulated the idea of turning it from a re-gas into a liquefaction with some of the optimism we had in the Horn River. What they're attempting to do right now - and we certainly support that - is to try to find a home, first of all, for the LNG, and I think you've seen some contracts for takeoffs going to go to the Asia market. The next thing they're attempting to do is get commitments by producers in terms of supplying the gas. So given the right commercial contract and circumstances, we might entertain that, but we really believe that there's a lot of liquidity in BC and if we develop the Horn River to the extent that we think it should be there shouldn't be any problem in terms of getting enough gas into that facility. What they really need, though, is someone to come and build physically a liquefaction plant. I think that's what they're tempted to do to match up the buyers and sellers, so anything that the industry can do to make that project go forward I think would be very positive for the natural gas industry in Canada and specifically for the Horn River.

You're probably not willing to put all your cards on the table, but what would attract you to be a supplier to the project? What kind of contract conditions?

Well, we would certainly have a contract that would equate to the other options we've got to sell our gas in Canada, so it'd have to be equivalent to some sort of [inaudible] pricing, station two pricing, something along those lines. But it's really premature for us to talk about that because it is just very preliminary discussions on those commercial interests.

The other question is on the Western Canada gas production. You made reference in the commentaries and also in the text itself about the royalties having an impact on your reported net production. Could you tell us what the gross production was before royalties from the first to the second quarter?

We'll get back to you after the call on that.

Your next question comes from Richard Wyman - Canaccord Adams.

I've got a couple questions here, some to follow up on prior ones. First of all, just for clarity on the drop in production in East Texas, was that entirely due to shut-ins or curtailments or were there other influences affecting production there?

That was entirely under our control.

And then in terms of the production at Haynesville you comment on Northern Louisiana as being gross 100 million a day. I presume that's all Haynesville. How much of that would be net?

Richard, about 100 million a day gross and about 75 million a day net.

And a question for Mike, just to get a little update on Montney production right now and how you see that changing as the year unfolds.

We're drilling about 60 wells in the Montney this year and then we're probably getting close to about 180 million cubic feet a day just out of the Montney alone. There's probably on the order of about 15 rigs running in the play; ourselves, I think we have four or five rigs running in the play. The Montney looks very encouraging. The costs continue to move down. We're doing our completions, frac completed, tied in, everything for on the order of less than $700,000 per interval now, so very attractive finding and development costs, sort of $1.50 range, even lower than that. So things are continuing to progress well in the Montney and we do have a tremendous land position and we're testing some more areas on the Montney, so we're very encouraged by it.

And with the Alberta royalties, are you moving that activity into Alberta rather than the focus to date in BC?

Yes, Richard, we've looked at sort of comparable royalties across BC and Alberta and both of them are actually quite competitive and both are talking about more stimulus programs as we go, so both are doing a pretty good job there. We do have rigs on the Alberta side as well in the area that we call Gordondale, and we like what's happening in Alberta. These couple-year incentives really help out the Montney and make it very comparable to what we're doing in British Colombia.

And then one last question here. There was a comment in the conference call earlier about capital efficiencies in the oil sands developments. Can you just put a number on that, dollars per BUE a day and how that might relate to historical experience?

We've just completed at Foster Creek the D&E expansions, which were each 30,000 barrels a day. Capital efficiencies on a U.S. dollar basis around $15,000 per barrel. At Christina Lake we are in the process of building a 40,000 barrels a day expansion there called 1C, and we're saying that that will be in the roughly $18,000 to $20,000 per flowing barrel upstream on capital efficiencies.

And in the context of historical experience, how do those numbers compare?

Generally fairly flat because we're building a lot of infrastructure in those kind of things in there. We are building a little bit for the future as we go forward. We're not seeing great reductions in overall capital costs there. We are seeing some improvements in productivity on the workers. The project that I've got going right now, the 1C, that's why I gave you a range of about 20, we've [parted] for about $20,000 a barrel and we're opening we can bring it in somewhere around $18,000 or $19,000.

Your next question comes from [Bart Polla] - Scotia Capital.

A question for you on SAGD operating costs. It came down quite significantly in this quarter. I was curious if that's largely just low gas prices or if you're seeing any other [break in audio] operating cost reductions there?

On the op costs, yes, we've definitely seen a reduction in our overall fuel gas costs because of the natural gas prices coming down, but also we've increased our volumes substantially at Foster Creek, in particular, and so on a per unit basis there's some reductions there. But I also think that we've been working with our contractors, our chemical contractors, our mechanical contractors, workovers and those things. We've actually realized some savings there. So the biggest drop has been on natural gas prices, but the efficiencies that we're gaining by additional volumes and some contract negotiations that we've had to reduce our suppliers' costs.

I guess as you're adding in 2010 hedges right now I assume you're starting to think forward to next year's budget and I'm just curious, depending how next year's pricing environment looks, how you weigh decisions in terms of capital spending cuts versus dividend cuts come later this year?

We've already put a significant number of hedges on, as we said, for 2010 and at this level we're starting to feel pretty comfortable about the amount of free cash flow that we'll be generating, so I wouldn't think that our dividend is significantly at risk at this point in time. But, of course, that is a Board decision that's made on a quarterly basis. With respect to our capital program, we have slowed down our capital program this year to target kind of a zero percentage growth rate. I would expect that if the market continues to be as it is now that that's what you might expect for next year. Costs continue to come down, so I would think that we may be able to achieve along the line of what we're spending this year, maybe even hopefully a little bit less. But that will unfold with time and we'll put our capital program out some time in the fall for 2010 - I think we may do it as late as December this year again - and that will be significantly based on what we see for market conditions at that time.

Your next question comes from Martin Molyneaux - Firstenergy Capital.

Gentlemen, given what you just said in terms of the heavy oil projects, I guess question number one is with the low gas prices is there opportunity to push more steam into the system given the lower cost environment and potentially even lower gas prices in August and September here? And I guess question number two is given the current oil and current natural gas prices is there any room for accelerating any of the heavy oil portfolio?

Martin, as you know, a lot of the things we do on the SAGD side are really longer-term decisions. I think we try to optimize the facilities at all times, so I doubt very much that there'd be much flexibility in terms of adding more steam. We typically don't react very much in that way. But in our Plains business unit - our Plains Division, I mean - we are reacting where we can to shift some dollars away from the natural gas development to heavy oil development and Don Swystun can comment on what he's doing there.

The most active area that we're pushing money into is right now into Suffield, particularly in that [inaudible] because of the Alberta incentives also that - adding some wells there. So we'll probably do maybe even up to 75 wells in the Suffield area. We're also looking at some additional wells, maybe in Brooks as well and some Saskatchewan opportunities that I think we'll be looking at drilling in the second half of this year.

I'm going to turn it over to John to answer the first part of the question, to either add or clarify something I said.

I think one of the things that we've really been focusing on in both Foster Creek, Christina Lake projects this year is really working on improving our operating efficiencies and not having any downtime. So we are looking to get as much oil as we can out of the ground. We are running our steam generators that we have and those that are built pretty much at capacity as best we can. We have approvals, regulatory approvals, at Foster Creek for the current projects that we're bringing on and we don't have additional regulatory approvals beyond that. We have made applications for expansions for FG&H at Foster Creek. At Christina Lake we have approvals for up to 98,000 barrels a day, regulatory approvals, and we're working with partners to sanction the 1-D here hopefully in the next quarter. And so we're trying to progress those projects as best we can. We have not slowed down any of our developments like some of the other operators had done when the oil prices slowed down.

Just in terms of following up with that, in terms of approval processes are you noticing slowing down or speeding up in terms of those exercises given the falling away of some competitors?

We made our applications. We're working with the regulators to move those through as quickly as we can. I think we're working as a company to provide complete and detailed applications; that improves the process.

And the last question here: In terms of Foster Creek and Christina Lake, fabrication costs for those facilities, have you seen any, like, are they where we have been previously or have you seen some erosion in capital intensity on the future [inaudible]?

I think we haven't seen substantial cost reductions because a lot of the things that we bought, like steam generators and steel and those kind of things, are ordered and bought ahead of tie. We may see some reductions as we go into these future phases. The things that I can say is that we are seeing improvements in worker productivity and we're not having the turnarounds that we had when we lost crews and stuff to other major projects in the Fort McMurray area and those kind of things. So we're very happy with the work force and the projects that we've got going forward. We think that we're cutting some time off of them. We used to say it'd take, say, 36 months; now we're saying maybe we can do them in 30 months and those kind of things. So ultimately when we do these new projects hopefully we'll see some improvements if the market conditions stay where they're at today.

Your next question comes from Mark Gilman - Benchmark.

First, Randy, Jeff, Mike, are there any physical well consequences to extensively deferring completions that ought to be taken into consideration?

We would take those into consideration before we decide to shut-in a well or not complete it. There are some things that can happen. Jeff mentioned that some wells may require some swabbing to bring them back onstream and in that kind of a situation there's always a possibility that you will do some near well bore damage. So we try to be very careful with wells that are wet producers, not to do too many of them. But Jeff and Mike?

When we look at the criteria for selecting wells, you know, one of the things that we looked at is their decline characteristics, the actual reservoir performance of the well, and, as Randy mentioned, carefully select the wells that we thought would have relatively low cost for bringing it back onstream. But there's a lot of other considerations that we took into account - obviously, our contractual arrangements, lease arrangements with our partners; another factor that's of significant importance is well data collection. There's numerous things that are local and we've asked our teams to specifically look at each of our areas of work to identify those considerations that are costly or that we just can't do and from that we were able to develop a strategy for each of our fields.

Okay, if I could shift gears a little bit, John Brannan, I believe the application regarding Borealis was probably submitted, I don't know, 9 - 10 months ago if my recollection's correct. Give me an update on where things stand on that.

We're currently waiting for the province to come out with the top water management. We've been consulted on that, reviewing on that, but I think really that's the holdup on that application.

So it's still pending?

Still pending, that's correct.

And just one philosophical question, Randy or Brian, if I could, you and I guess others seem to be thinking that natural gas prices will remain weak in 2010. I'm wondering as you think about the capital budget for next year whether it will be a budget that would be predicated upon generating free cash flow in the kind of price environment that you now seem to envision?

Yes, it will. That is basically how we've been trying to operate the company for the last number of years. And so we can control the size of our capital budget, although we do, as much as possible, like to take advantage of the current market conditions for the service sector, you know, getting jobs done; we can do them quite a bit less expensively. We see value in keeping our teams operating at a steady pace. We see value in making sure that the service sector is actually healthy in all the areas that we operate in as well. So I wouldn't want to take it down too low. We always have an underlying target of creating free cash flow, but I'd say we could give up some of it and there's other ways to create it. So it won't be the end all, but it will be a factor in creating the budget.

Randy, would you agree at least on the basis of rough numbers, it frankly looks to me as if in, just to pick a number, a $5 kind of environment that there's no way in 2010, even with the hedges in place, that you could spend at a level sufficient to hold production flat.

I haven't come to that conclusion yet because it really is going to depend on the input costs, and if the commodity price, I'd say, continues to stay at that level we're likely to see a continued degradation of costs. So I'm not there yet; I have to do more work. I'm just not there yet.

Okay, just one more for Jeff Wojahn. The decline I guess referenced in a previous question in East Texas in Deep Bossier, I would imagine, in particular, quarter-over-quarter, the first quarter was impressive. Should we infer that at least the variance which is well over 100 a day right there is all deferred completions?

Mark, it's deferred completions as well as curtailments. You know, in East Texas we have royalty owner partners and we have discussions with each of those partners in regards to their appetite for curtailment and based on that we curtail these wells. Because the Deep Bossier has unique properties that allow it to be turned on and off without very much well damage or cost associated with it, it's an ideal place for curtailment and shut-in and hence the reason why you saw the quarter-over-quarter reduction in production of about 100 million a day, about half of the division's 200 million a day of shut-ins and curtailments. I should also mention that in East Texas we drilled or completed a half a dozen wells and their original 30 day IPs averaged over 20 million a day, so we are ahead of budget from a performance point of view, but we've made some decisions on production there.

(Operator Instructions) Your next question comes from [Dan Trozo - Rice Hall James].

I have a few questions on Haynesville. I think you mentioned earlier that you completed 15 wells or so in that area. I'm curious how many wells you expect to complete in the next 12 months and what is your long-term goal for Haynesville?

We earlier talked about our strategy in the Haynesville to drill and complete 50 net wells this year with a plan to drill and complete 100 net wells next year as part of our land retention strategy. So we envision over the next 30-month period to have 250 net wells as part of our land retention strategy to basically hold our leasehold position in the area.

And along those lines, what has your experience been with the use of resin-coated sand versus ceramic-coated sand, not only in Haynesville but maybe in other areas?

That is a factor dependant on the specific areas that we operate in the Haynesville. We have done a fair amount of experimentation on resin coated versus ceramic [prop] and because of the high confined pressures in the area I think the de facto solution that most operators have gone to is the ceramic sand.

You think it has a better long-term payback?

Well, we'll find out. I mean, that's one of the trials and tests that we're currently undergoing. We have pumped straight sand, we've pumped resin-coated sand, and we've pumped numerous different ceramic sand combinations, and one of our optimizations as we move towards a better understanding of the play is to identify the cost benefit of those three particular options. We haven't made a conclusion to date yet.

What is the cost significance between resin-coated and ceramic?

Cost-wise I think the cost for ceramic sand on a typical job is approaching $1 million and resin-coated is about half that, so there's a significant cost benefit. The issue is whether we see a type curve benefit or a difference in the decline characteristics.

I expect that this is an evaluation that's going to take a very long time to determine and will likely change significantly with time?

That's right. It's going to be years.

Your next question comes from Shaun Polczer - The Calgary Herald. Please go ahead.

I take it from Randy's comments on Horn River that [inaudible] is ready to go full commercial scale and, if so, what would that kind of a development look like in terms of wells, capital spending and production?

Okay, I wouldn't say we're going full commercial scale. We're still at a fairly early point in evaluation as to how big a development that we might ultimately see in the area. We will expect as we get more and more results in we'll start putting those plans together, but we do not have a full long-term development plan yet. It would be much too premature to develop that because we really don't know what the long-term characteristic performance of the wells are going to be. What we've said is we are very encouraged with the results to date and we're taking a number of steps to make sure that we can bring production onstream for I guess the next couple of years. Mike, you can say what exactly we have in front, the plans that we currently have with industry.

Yes, Shaun. For this year in the Horn River we're actually going to drill somewhere on the order of about 18 net wells, which is actually up from what we said in the last quarter. We're actually drilling more wells and really completing less wells, if you will, so we're going to defer a lot of that, some of that, into 2010. Like Randy talked about, we're very encouraged with the rates. Our last couple wells are 12 and 14 stage frac and, you know, midway through the month they're still probably producing in that 9 to 11 million range. The bigger the frac, it seems like the better the well, similar to what you'd find in any of the other shale plays as well. Our drilling costs have come down significantly. We've gone from about 25 days to 16 days on some of our drilling. And, you know, from what we see today - like Randy said, it's very early yet; we've only had wells on about a year in this play - but our declines are relatively shallow. We're very happy with where we think our EURs are going to end up on these wells if we can get our costs in line and continue to prove this play throughout the basin it'll probably turn into one of our Key Resource Plays as we move on.

So how would it stack up against some of the other plays that you have in Louisiana and Texas in terms of competitiveness?

Well, I can tell you right now, like it is very remote up in Northeast BC, so the cost structure is a little bit higher. Now, we do have lower royalties; the BC Crown has done a good job in [inaudible] industry. On a supply cost it's probably in at least the top half of our portfolio, somewhere on that order, but there's still room to move on the cost and then that's where we're really focusing in on, especially around the completion cost.

I think it's fair to say that the supply cost is probably at least $1 higher just because of where it's located.

There are no further questions at this time. Please consider, Mr. Gagne.

Thank you, everyone, for joining us today to review EnCana's second quarter results. We would like to remind you that in 2009 EnCana is hosting a series of conference calls highlighting several of the company's key plays. Please mark your calendar for the next conference call, scheduled for Thursday, September 24th at 9:00 a.m. Mountain Time focusing on our Integrated Oil Division. Additional details will be available at a later date. Our conference call is now complete.

Thank you, everyone, for joining us today to review EnCana's second quarter 2009 financial and operating results. Our conference call is now complete.