Good day, ladies and gentlemen, and thank you for standing by. Welcome to EnCana Corporation's Second Quarter Financial And Operating Results Conference Call. As a reminder, today's call is being recorded. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. (Operator Instructions) Members of the investment community will have the opportunity to ask questions first. At the conclusion of this session, members of the media may ask questions. Please be advised that this conference call may not be recorded or rebroadcast without express consent from EnCana Corporation. (Operator Instructions) I would now like to turn the conference call over to Mr. Paul Gagne, Vice President of Investor Relations, EnCana. Please go ahead, Mr. Gagne.

Thank you very much, operator. And welcome, everyone, to our discussion of EnCana's 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 in the advisory on page one of EnCana's annual information form dated February 23, 2007, the latter which is available on SEDAR. I would 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 the 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 an overview of our results and then turn the call over to Jeff Wojahn, President of our U.S. Division, to provide further highlights on some of our key U.S. gas projects. Brian Ferguson, Chief Financial Officer, will then discuss in more detail our 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, President and CEO.

Thank you, Paul. And thank everyone for joining us today. As you saw in our press release this morning, EnCana had strong second quarter results. With two quarters behind us, I'm pleased to say that 2007 is shaking up according to plan. In short, production was on track to meet full year targets and capital costs are tracking below budget at midyear. Cash flow has been higher than expected and we have revised our guidance accordingly. I believe that our performance is a result of the deliberate actions we've taken over the last several years to transition the company into a leading integrated producer of unconventional natural gas and in-situ oilsands. A company with a unique low risk sustainable growth profile. Now let's look at how the strategy is paying off by reviewing some of the highlights from our second quarter. First, our bottom-line performance was strong. Though by increased gas production and gas prices, financial hedging gains and very stronger refinery margins, cash flow increased to approximately $2.5 billion or $3.33 per share diluted, that's up 55% on a per share basis compared to the second quarter of 2006. Operating earnings increased to approximately $1.4 billion or $1.80 per share diluted, an increase of 84% on a per share basis compared to the same quarter last year. As well, during the quarter, we generated approximately $1.4 billion in free cash flow. When you add this to the free cash flow from the first quarter, the total is close to the amount we had originally expected for the full year 2007, in part due to unusually strong margins in our refinery business experienced in the second quarter. We don't think it is reasonable to assume the refinery margins, or crack spreads as they're known, will stay at recent levels. But…

Thanks, Randy. The U.S.A. Division had a great quarter. Our key resource plays are performing better than expected and our gas production averaged 1.3 billion cubic feet per day, up 11% from the same period in 2006. This growth was driven by our four key resource plays, Jonah field, the Piceance Basin, East Texas and Fort Worth. At Jonah, production averaged close to 525 million cubic feet per day, 16% higher than the comparable quarter in 2006. During the quarter, we averaged 11 rigs operating in the play, seven of which are fit for purpose and we're very pleased with their performance. Cycle times have improved between 20% to 30% on average due to improved drilling efficiency. It appears that the completion problems that we've experienced late last year have been resolved. Year-to-date, average initial productivity have ranged between 3.5 million to 3.8 million cubic feet per day. In addition, we are starting to see the benefits of the compression expansion project and anticipate pressure reduction benefits during the next few months. Consequently, we have revised our full year production expectations to 500 million cubic feet per day up from 460 million cubic feet per day. Production in the Piceance Basin averaged about 350 million cubic feet per day, an increase of about 8% from the same period last year. Growth in the Piceance was driven by more efficient development programs, a larger program in north Piceance and attention to base production through workovers and artificial lift optimization. We currently have 16 rigs running throughout the basin and expect to maintain this level of activity through the remainder of the year, as we execute our planned drilling program. In the mid continent, East Texas has seen the greatest year-over-year growth with an average production in the quarter of about 140…

Thanks, Jeff, and good morning, everyone. As Randy highlighted, our financial results for the quarter were very strong. Cash flow was $3.33 per share diluted, more than 30% ahead of street estimate. In addition to excellent upstream results in our core business, there are two key items that increased our cash flow. First, as Randy mentioned, our downstream operating cash flow for the second quarter was tremendous, at about $440 million, largely driven by strong crack spreads. In the quarter, U.S. Gulf Coast 3-2-1 crack spreads averaged $24.28 per barrel, up significantly from the first quarter average of just over $10 per barrel. The second item was a non-operating cash tax recovery of approximately $175 million or $0.23 per share diluted to reflect tax legislation regarding deductibility for Crown royalties. It was approved by parliament during the quarter. This also had an impact on operating earnings. Net earnings for the second quarter of 2007 were $1.4 billion or $1.89 per share diluted. That's down about 26%. You have to remember that the second quarter of 2006 included some one-time items, particular a gain on discontinuance, mark to market hedging gains, foreign exchange gains and the impact of tax rate reduction. In aggregate, these items in the second quarter of 2006 accounted for about $1.3 billion of that quarter's net earnings. But in Canada, we focus more on cash flow and operating earnings to judge our performance. On the cost side, we continue to see an easing of inflationary pressures across the industry, with the exception of labor and energy related costs. Generally speaking, in Canada, excluding the oil sands, we have experienced inflation in the range of 0% to 5%. In the U.S., activity remains high and although inflation is moderated in some regions, it is still expected to be…

Thank you, Brian. Our strategy remains very focused on onshore North America on unconventional natural gas and integrated oil sands and we believe that we're well positioned to deliver our results on target for 2007. We also know that the year is not over yet and there are a number of external factors that can influence our success. High storage levels continued aggressive drilling in the U.S. Rockies and Texas. Higher recent LNG imports and the lack of a hot summer weather in key demand areas have caused short-term gas prices to pull back. As we know from watching gas prices over the past few years, there has been a lot of volatility and prices, for short periods of time, hit extremes on either end. We may be in for some bumpy prices near-term but overall, we remain bullish on natural gas and we expect continued industry challenges to offset decline and add production. Numerous studies suggest that the industry needs sustained prices higher than what we're currently seeing to bring on new production. In the short term, as Brian said, we've taken steps to limit our downside risk with hedges on commodity prices and basis differentials. I believe that a disciplined, low-risk technology-focused company like EnCana can perform well through a variety of market conditions and will really be able to showcase its strengths in periods of softer commodity prices. As always, we're focused on optimizing the factors that are within our control and minimizing our exposure and risk for those that are not. Success for us in 2007 means excellence of execution and delivering on our potential and we continue to work toward these goals. So far, our results have been very positive, a credit to our teams, our assets and our strategy. Thank you very much for joining us today. My team is now ready to take your questions.

(Operator Instructions) We'll now begin the question-and-answer session and go to the first caller. Your first question comes from Brian Singer of Goldman Sachs. Please go ahead.

Thank you. Good morning. Randy, I was wondering if you could give us your thoughts, given that production has been quite strong for the last couple of quarters, especially in the U.S., what you're thinking about in looking out into 2008 in terms of the right growth rate versus the right level of spending.

Okay. Brian, we've had pretty good look at our portfolio and as we've said in the past, it is capable of growing at a fairly high rate if we put a lot of capital to it. But we have decided that it is in our best long-term interest to have a lower, more moderate growth rate, something in the range of about 5%. Just slightly higher than what we're likely to achieve for this year for natural gas. On well sands, our growth will of course be somewhat lumpy as a result of oil sands projects coming on every couple of years. And that should pick up our overall growth rate slightly higher than that 5% mark. Little hard to tell right now, what it is going to take for capital program for next year as we've said. Things seem to be softening a little bit in Canada. But still, experiencing some inflationary pressures in the U.S. I would expect our capital program will go up a little bit. Certainly to account for that inflation and for that additional growth. But then we'll also -- we do have a fairly large spending year in our integrated oil sands unit for next year that will pop up our capital a little bit higher than that than what we're exposed to this year. We're also looking -- we did cut back our exploration program from the historical spending levels. You might recall we've been spending somewhere in the order of $600 to $700 million per year in -- for exploration spending. This past year, we cut it down to about $200 million. We're seeing some opportunities that we may want to pursue in the upcoming year that would take the level to a number somewhat higher than the 200.

Great. That's helpful. Speaking of exploration, can you give us an update on any exploration results and maybe with some particular attention to any of the shale activity in Canada that you're looking at?

I'll turn that over to Mike Graham. He's working on our foothills business unit.

Mike Graham here with the Canadian foothills division. We are, Brian, working on shale plays in western Canada as you alluded to. But we're really not seeing too much at this time. It is pretty early but we do hope, you know, that shale gas will emerge in Canada.

Great. Thank you very much.

Thanks, Brian.

Thank you. Your next question comes from John Herrlin, Merrill Lynch. Please go ahead.

Hi, Randy. Your well count year-to-year is basically flat. And as you said, your CapEx is down and you're spending less on exploration. How much of the difference is not spending on things like infrastructure, gathering processing systems? Because its not like well costs have dropped that much?

I'll turn that over to both Mike and Jeff and Don to give a brief synopsis. I think it is probably not quite as simple as well counts versus cost there are a whole bunch of factors. I'll turn it over to first, Mike Graham.

Hi, John. Mike here. John, I know in the deep basin of Alberta especially last year, we did have a lot of infrastructure costs. We built a new gas plant at an area we call Resthaven as well in an area we call Cakwa and also sort in the deep basin of British Columbia, if you will. We built another gas plant, what we call steep rock. So, definitely in the foothills division, infrastructure costs are down but with that being said, we're seeing a tremendous amount of efficiencies as well. You know, we have essentially our entire fleet now in Canada are close to it in the Canadian foothills division is fit for purpose equipment and we're seeing sort of 25% to 30% more efficiency across the board and that is starting to reflect in our -- in the costs of our wells.

Don, do you have anything else to add in Canada?

I would just suggest that we spent about $340 million of that amount, probably 50% of the cost was towards drilling and completions and maybe a third was to infrastructure spending.

Any changes over year-over-year?

No, not any significant changes. Maybe last year we spent a little more on pelican lake just a really sufficient not as much.

Jeff? I know you've had similar responses Mike has had.

Right John. It's Jeff Wojahn speaking. We really haven't changed on a percentage basis or absolute base our spending pattern on our midstream business year-over-year. The efficiency changes in our fit for purpose rigs and also our overall cycle times have driven the reduced capital and increased results you're seeing in the U.S.

Super. Next one for me, prices are weak. Gas is about $6. For argument's sake, say it stays around $6. I mean obviously you've got your basis hedge, you've got a good hedge position for 2007. Would you swing gas in the past, you used to put gas into storage. Would you do anything like that or curtail activity if prices really did stay weak?

John, for the most part, we do try to treat all the -- both the physical hedges, the financial hedge positions that we have put on and our basis hedges as if they were physical positions, because we really would have tried to do them in a physical sense if we could have. So, that being said, we have a tremendous amount of protection in the U.S. Rockies, where we're experiencing the biggest loads in basis. But when it -- as it applies to NYNEX price, it would have to get down significantly more than that before it would actually impact our overall operations to the extent that we would want to shut in different areas. But it’s the same thing we've considered in the past and we've reacted appropriately in the past, if prices fall much further.

Ok. Last one for me. What about acquisitions? Are you seeing anything kind of complimentary that would be type of -- build-on type of things for you?

We've looked at a number of things, a number of opportunities here. We're setting our targets fairly high, primarily because we really don't need to do any acquisitions. So we want to be able to make sure if we do them, we're able to create a significant amount of value vis-à-vis drilling more in our existing program. So, we're likely to conduct a couple by year end. And we think that the -- if gas prices stay low for a long enough period of time, it will create opportunities for us and we'll be able to take advantage of them.

Thanks very much.

Okay. Thanks, John.

Thank you. Your next question comes from William Farrah, W. H. Reeves and Company. Please go ahead. William Farrah - W.H. Reeves & Company: Thank you. Good afternoon. Two questions. Could you just update us a bit on non North American EMT activity if any? And separately, there was a program to form out some of your acreage to other folks who might be interested in drilling up properties at very reduced costs net to you, but give others in that an opportunity, perhaps to exploit some of your landmass that wasn't being fully exploited. Could you just give us an update on that program? How that seems to be doing and is it really helping costs or production in any fashion? Thanks so much.

Okay. To answer your first question, we really have very little activity happening on the International front. We are drilling in our second well on a resource play on the south of France, and that’s likely to be part of the three well program. And we are in a process of divesting of our interest in Brazil right now. And we have a little bit of other activity, I think going on, Gerry, in the Middle East.

Yeah, we drilled two wells in Oman and we have two of our programs coming up in the remainder of this year in Qatar.

These things are relatively minor overall in our portfolio. With respect to the farmouts, I'm going to have both Jeff and Mike talk about what they've done in their areas.

Hi, William, this is Jeff Wojahn calling from the U.S. division. In regards to farmouts, earlier this year we provided a corporate guidance, but I guess a goal or an objective of farming out $450 million of program in the U.S. and I believe $150 in Canada. And the thought crossed us because behind that was two-fold. One was in many areas like the Piceance Basin, we have an inventory far beyond ten years which is how we categorize our inventory of wells. And that we just weren't moving the programs along as we would like based on just having this really strong land position in those areas. And we have decided that we would like to accelerate some of that work beyond what we're capable of doing in the next ten years and hence we’ve been doing some deals. The second type of farmout deals that we've done and Randy, mentioned earlier that we had cut back on our expiration spending again, because we had a ten-year inventory of drilling. The need for expiration in our portfolios is really small relative to our business plan. And so, we've been bringing in third party capital to help us on some of our expiration initiatives. In both cases, we've been able to track parties and then I think in both cases, we’ve been able to bring forward partners that can help us reach those two goals that I mentioned. And so when I look at relative to our former $50 million target, I believe we're on track to be successful. And I think ultimately as those expiration -- exploitation programs roll through, in time we'll see the full benefit of those programs. William Farrah - W.H. Reeves & Company: Let me just try it another way as well, just to just as another sense as to how that program is going. Would you plan to do the same thing in '08 as you are targeting for '07? You want to do it again?

We really haven't looked at our budget for 2008 in great detail. But I believe the same conditions that we had in 2007 should be there in 2008. In other words, we have a very large land base, a lot of land and opportunities that are beyond the scope of our budget and therefore, I would expect that we would have a likely -- the similar type of program next year.

I think the only thing is we look at different parts of our portfolio where we could take the most advantage of bringing in third party money to reduce our risks. So, it’s maybe that we do these type of programs in different priorities. William Farrah - W.H. Reeves & Company: Mike, thank you.

I could add a little bit in Canada as well, we do have a tremendous land position in the order of 20 million net acres and about 8 of those are on fee lands. Over the last three years in Canada, we've probably brought in close to a billion dollars of third party capital, you know, on those lands. We target a lot in early life resort plays like Jeff talked about as well as conventional exploration. With the resource, we'll often have good conventional prospects on there. We have a team set up in Canada that is strictly looking for conventional prospects and we put those on the shelf and we don't really capitalize them ourselves. We've been pretty successful at that to date, William. William Farrah - W.H. Reeves & Company: Thanks, Mike.

Thanks for the call.

Thank you. Your next question comes from Gil Yang, Citigroup. Please go ahead.

Hi. A follow on lines that some of the questions.

Thanks, Gil. No. The strategy we would undertake, it was basically a strategy that resulted from a change in our -- in our growth profile that we were pursuing. We went from the higher growth profile, trying to achieve something in the 8% to 10% range and cut it down to the -- in the rake of 5%. What we realized is that our inventory of wells and land that we had acquired on the previous strategy now became quite long and really created an opportunity for us. To start monetizing value of that land that we wouldn't otherwise get to for a very long period of time. As we really started looking at it, as Jeff was saying, it adds value to our early light resource plays by helping to share in the initial infrastructure costs and the exploration risks on the lands.

It is not something we would pursue directly by acquiring new land and then doing the same thing on.

Ok. Fair enough. I guess related to that is Randy, you made the comment in answering Brian's question that it was in your best interest to grow, yes. Production of 5%. Could you just maybe let us get inside your head a little bit. Describe what you meant by that in terms of what are the factors that you weighed in terms of looking at the portfolio.

Well, we built the overall portfolio to grow at a higher rate but when we realized -- what we realized is that in order to achieve the high rate of growth, we would have to be drilling our inventory at a very, very strong rate.

It didn't provide us with as many choices in our inventory. Particularly in situations where you had changing industry conditions like higher inflation in one area or higher activity levels being created by one dynamic or another. And as we sort of assessed the situation and really started detailing the potential cost implications, we realized that to go with the higher rate, we tended to have to bring in less efficient equipment at higher costs. And by backing that out, that -- it had a very major impact on the returns that we were able to get. And so with the lower growth profile, we're able to achieve returns are probably as close -- with the higher growth strategy but using the extra money, the free cash flow, that would be left over in our portfolio to buy back shares. So, in the end, we think we're at least as well ahead or maybe better and now we have a long inventory of wells in front of us so I think we've created a really winning situation for the company.

Given the more moderate cost inflation environment that we're in and the efficiencies that you're getting in the rigs, is there any chance that maybe you would reevaluate that lower growth strategy?

We would evaluate it on a play-by-play basis but the advantage of having choices outweigh the benefits of a higher growth rate. Higher physical growth rate.

If I may ask one more question about exploration. You were saying -- can you talk about what's going on offshore in Nova Scotia right now?

On the exploration front, we have virtually -- we have nothing going on. All we're doing offshore is looking to pursue the development of our deep new prospect, which -- I'll turn it over to Gerry to give an actual update on that.

Hi, Gil. We're going through the process of -- we've been working with two suppliers bidding on the field production center mode ac and SPM. They've been getting documents together so we hope to have some bids in by the end of the summer. We're awaiting the results of the regulatory process and we continue our commercial negotiations with Exxon Mobil and looking at our transportation options. So, we're still planning to move forward with project sanction decision in Q4.

But no other exploration planned in the area.

That's correct.

Thank you.

Your next question comes from Mark Pollack, RBC Capital Markets. Please go ahead.

Thank you. Just a few questions on refining and now that the borger Coker is up, would that be sin bit you guys are running through there?

Hi, Mark. I'm going to turn that over to John Brannan to talk about our plans there.

Hi, Mark. You it is a. Borger Coker that we just started up the end of June. We actually ran some of our first WCS through that July 10th or so. About 10,000 barrels a day and they're working that to working to ramp that up through the refinery system as they fine tune that Coker into the overall process.

Are there any major turnarounds planned?

No. Not for the rest of 2007 of.

With the works Italian, the Coker, would that have been one of the reasons for the slightly higher operating cost this quarter and would you expect maybe you know, fall back to more of a Q1 run rate going forward?

Yeah. I would expect that we'll be back to the run rates for Q1 border at 145,000 or 146,000 barrels a day was down for about 30 days. And it is overall efficiency is a little bit higher than the efficiency of the wood river plant. Operating costs would have been up because there was no associated production for those 30 days.

Great. And then finally, would you guys consider any hedging on the crack spread front going forward?

Currently, we have no plans on that.

No, Mark, no plans on that.

Ok, great. Thanks a lot, guys.

Thanks, Mark.

Your next question comes from Stephen Calderwood, Raymond James. Please go ahead.

Good morning. I have two questions. One on booked reserves and one on rocky's pipeline. First, the pipeline question. Could you please comment on how you see things unfolding in 2008 when the next phase of the rockies express expense is commissioned. I believe you've got about 550 million cubic feet per day. Do you anticipate having sufficient direction of your own to fill up the capacity in the first part of 2008 or do you observe -- a lot of suspended gas production in the area for third parties, it may permit you to offer some of your capacity to other operators.

Steve, I'm going to turn it over to Jeff Wojahn to answer that.

Yeah, hi, Steve, it is Jeff Wojahn. In regard to capacity, we have a BCF a day out of the rockies right now. Meeting the needs through our transportation system will be fine. With our current transportation. In regards to shedding transportation, we have made that decision -- we haven't made that decision today.

The second question on booked reserves, investors, you've already mentioned very concerned about the downward trend in natural gas prices at the end of this year. Now, I know that you've managed your risk on the operating side with your hedges but what gas price do you start to get concerned about proving undeveloped reserve write-downs or do you think investors shouldn't be concerned about proven unreserveds?

Well, I think we can reflect on what price we had last year. It was pretty low. I think it was in the $6 range. And so we -- that that is the basis for our reserve booking. At the beginning of this year. Our long-term outlook for natural gas prices is, as I said, you know, is really dependent on what the supply cost is in North America because we still have a very high decline. Although we may have a booking issue which could develop on any given year if you ended up with really, really low gas or oil prices, we don't see this as a long-term issue and you know, it is just a booking issue.

Steve, it is Brian Ferguson. Maybe I can just add that at year end, NYNEX was a little bit less than $6. We had several billion dollars in ceiling test surplus both in Canada and under U.S. rule so they would not anticipate ceiling test breakdowns with those kind of prices.

Great. Thanks a lot.

Thanks, Steve.

Thank you. Your next question comes from Bob Morris, Banc of America Securities. Please go ahead.

Good afternoon. You mention that your spending is running below budget. Two of the reasons being lower service costs and better efficiencies on your rigs. I assume you'll probably maintain your budget but drill wells someplace. I was wondering where you would add to your well count.

Bob, although that appears like the possibility right now, we're basically basing our capital forecast for the remainder of the year on the assumption we'll drill the number of wells we put in our budget. So, maybe it is a little bit conservative positioning by our teams.

Ok. So, the efficiency gains and lower service cost remain in place, you may end up spending less?

Again, so many moving parts, there's land sales to take into consideration. There's some other plans we might put into effect. So, I would say very close to our targeted budget is what we expect to spend at this point in time.

Because I guess in that regard, you mentioned last quarter things were running ahead of schedule and you continued to have the success you had then, that you might increase the activity or guidance in east Texas. Neither of those are doing that poor right now?

One of the answers to that is we're dropping some of our nonfit for purpose rigs in the area. Beyond that, I'll turn it over to Jeff. In regards to Fort Worth, you are correct in the assumption that our efficiencies are running ahead and our well count was running ahead. In the last month, we've had flooding and major rain which has slowed our cycle times down. As I mentioned earlier. In the end, we're essentially still ahead of our planned targets but you know, we were dramatically affected by the rain in the sense that previously, we were well ahead of our plan. Now we're on plan or slightly ahead of plan. So, things have a way of equaling out. But I think my intention, my team's attention is to -- as Randy said, stay on budget and in some cases, release some of the poor service providers or older equipment out in the field.

Same case with east Texas you mentioned last quarter you might boost production guidance there. You continued just like you had.

Well, you know, if it happens, we will like -- we did in Jonah this last quarter, but it hasn't happened yet. So, we'll see how it goes.

Okay. Thank you.

Thanks, Bob.

Thank you. Your next question comes from David Tameron of Wachovia. Please go ahead.

Hi. I guess it is good morning. Question, as John Herrlin asked the question but I wanted to dig deeper. If you look at someplace like the PEANCE, come September or October, is there any thought of any just drilling wells, not hooking them up, not completing them until the price improves? Is that part of the thought process if you still have a $3 differential two months away.

Well, with the lowering of gas prices often comes a reduction in inactivity and sometimes the best thing that we can do as an operator to create shareholder value, is be somewhat countercyclical in the drawing and the completion of wells. So, picking up our activity or at least maintaining it at a constant level during periods of reduced service cost, can create a significant amount of value. And you're right in the sense that, it is not necessary then to turn that production on but -- into the low environment if you don't have to. So, it is kind of similar to the question we had earlier about whether or not you shut in gas. It’s the same issue, just basically phrased differently. And yes, we would consider it.

Okay. And what are your earn out on Rex? We've heard different reports. Some says it’s going to be delayed a little bit. Some says its on time. What is EnCana's latest?

I'll turn that over to bill Oliver.

The latest, from what we understand, is it will be on stream in the first quarter of 2008. I know there's some other reports out there. But we can’t confirm that I think you need to talk to Kinder Morgan and determine what their best estimate is. But we're planning on the first quarter of 2008.

All right. Thanks.

Thanks, David.

Thank you. Your next question comes from Mark Gilman of Benchmark Capital. Please go ahead.

Hi guys good morning. I had a couple of things if I could. Mike, can you comment at all on recovery rates that you're seeing in the Monteny how they’re compared to the Doig Cadomin about the Monteny.

Hi Mark, Mike Graham here yeah. We’ve had a Randy alluded to it in his talk on the conference call. Very good success in the Monteny. We think we can probably recover above 50% of the gas in the Monteny. We're using a lot of U.S. technology. Now we're drilling horizontal wells at about 2500 meters to vertical depth, and then they got another 2,000 meters beyond that on a horizontal. And the wells are coming on good rates anywhere from five to 10 meters 50 to 80. And we're very pleased with what we're seeing in the Monteny. And we do have a good land position now, probably in the order of about 320 net sections on that plain today.

And Mike how do those recovery rates compared to the Doig and Cadomin.

Well, I’ll tell you what, they'll be a little bit less the Doig at least the Doig works and we’ve fairly prolific and fairly poor to radiant year. You're probably going to get 75% recovery out of the Doig and you’re probably going get a little bit more out of the Montney to put the Cadomin, but somewhat it terminates that 50% as well in the Cadomin.

Okay. I was wondering whether any significant thought at this point has been given to additional vigilant processing arrangements, either within the scope of the joint venture or perhaps out outside of it.

No, there hasn't at this stage. Basically, the joint venture itself created an opportunity for us to not have to pursue anything too aggressively in the near term. It really bought us a significant amount of time. But as we go through and work through the opportunities that exist at the two existing refineries, we start thinking about the future, we will be investigating it both within the partnership, and then we still have our separate project which we hope at some point to take commercial or Borealis project. And for that particular project, as I said earlier, everything is on the table. Although I said everything is on the table. I didn't mean we were actually pursuing anything right now. So, it’s really something we would do more down the road.

Okay. It’s like back to Mike Graham for just a second. I assume the drop-off and second was drilled both in the Bighorn is well a shallow gas is weather related, is that correct, Mike?

That would be correct. Typically in western Canada, you know, second quarter, we're a little bit low on our drilling but we -- you know, things are dried up very nicely. And we're moving pretty good now especially in the coal bed methane area as well as Bighorn.

Okay. Just wondered if I could for Brian Ferguson. I'm a little bit confused about the tax item that you mentioned. I think you used a number $175 million yet I believe the release refers to about $230 million. Could you help me understand that discrepancy?

Certainly. It is not a discrepancy. The $175 million is the current cash tax impact. The $231 million includes a $57 million in future tax related to 2008. So, that's the difference between the two numbers.

Okay. But it is the $230 million that's included within reported results for the period.

On an earnings basis, correct. There's $57 million in deferred tax for future tax.

Got it. That's all for me. Thanks very much.

Thank you. Your next question comes from Bob Lyon, TD securities. Please go ahead.

Hi, good afternoon, everybody. Couple of quick questions. Firstly, you know, a lot of what you're talking about is obviously a bit of a push more toward perhaps capital efficiency at the expense of growth, which I applaud by the way. It kind of leads me to look at the MLP market. A number of the ENPs have turned to that market. Can you speak to how seriously you may or may not be worried about those kinds of options or maybe it doesn't apply to you at the moment.

I think it is fair to say we're watching it with a great deal of interest. The MLP market as we did watch the trust market develop in Canada and eventually, participated in that with the sale of some of our more mature non-core assets over time. The market itself is quite small relative to what we think it ultimately will become. As a result, there may be times in the future where of some our more mature assets could be sold or we could participate directly in that by creating our own. But that would be speculation at this point in time. It is something we're just really watching.

Okay. Fair enough. Second question, if I may. The share buybacks to date looks like a large portion of that has been funded with, you know, asset dispositions. Do you have a sort of goal or target for free cash flow generation in a normalized environment? I'm not sure I know what a normalized environment anymore but do you have a goal or target for free cash flow generation or share buybacks, either of the two?

Actually, the share buybacks s have occurred historically, have largely been related to the capital dispositions we've done as we overall changed our portfolio from an International to one focused on resources in North America. When they sold out Ecuador, we used that money to buy back the shares. So far this year, only a small percentage came from divestitures. The large part did come from out of our free cash flow, which has been -- we're expecting to be in the range of about $2 billion for the year. On a go-forward basis and what we announced last fall when we said our budget was that, we would target having a capital program that was no more than 90% of our expected cash flow for the coming year taking into consideration what we thought was a fair range of estimates for commodity prices and taking into consideration all of the hedging programs that we had already conducted. So, that will stay in effect. That will have a minimum, a 10% pre-cash flow target. We first target with that pre-cash flow, buying back any dilution or pseudodilution that would be created by our long-term incentive programs. That amounts to historically 1.5% or something like that per year. That would be embedded in it. Then increasing our dividends is another option. That we would look at in parallel with buying back additional shares with the rest of the money.

Ok. That's good guidance. Thanks. Final question if I may, east Texas, you've obviously had some good success there. That it shows your play at -- a number of fairly high deliverability wells. Can you talk about the sustainability of that production and a bit of the program going forward there?

I'm going to turn that over to Jeff.

Hi, Bob. Right now in east Texas, we're delineating the emrousseau field and we have a six rig program going on there. We're already shooting a 3 had 3-D seismic program as well. You know, we really feel that this play will fit our resource play model long-term. We currently have had a number of -- what we consider very unusual high productivity wells that we've drilled about and they've received some amount of, you know, fanfare I guess the word to use in the industry because they have been -- I think it is fair to say some of the best wells drilled in east Texas and even in the U.S. here recently. But our intent would be that our average wells will not be in that range. We believe that the tight curve will be in the 8 BCF ultimate recovery range with IPs much lower than some of the big wells you've seen. We think that will be sustainable. We think that as we have a better subsurface model with our 3D seismic, that we'll be better able to describe the portfolio. Right now, it is very exciting. Looks like it has got a lot of legs. We're just getting started.

That's good. Thank you very much.

Thank you.

Thank you. Your next question comes from Martin Molyneaux, FirstEnergy Capital Corp.

Just let's move on because my question has been answered.

Thank you.

Thank you. Your next question comes from Tom Covington, A. G. Edwards.

Thanks. Just a follow-up on the prior question. Jeff, outside of Omarosa field, are you drilling any wells now or is it strictly 3D seismic at this stage?

Tom, outside am Omarosa, we have a program on the shelf in the four County area, a fairly significant land base there and we've had good results there. It hasn't been as large of a focus as Omarosa but we continue to evaluate our opportunities there and I should also say that we have several exploration third party wells that are being drilled on the trend and hopefully we'll have some success as well.

No. Wells outside of Omarosa right now? Just 3D seismic work?

As I mentioned, we have several exploration wells on trend being funded by third parties that we're partners with. We also, I should mention a fairly large extensive land picture. I think it is fair to say that with time, you'll see more activity along the trend from EnCana you see a little bit today. But we're very well-positioned long-term.

Okay. And Mike, one follow-up for you, reminder he me what the Montney well costs are and is there room for optimization on those costs?

Hi, Tom. We've been working hard on our cost in Canada I think like Jeff was alluding to in the U.S. And the costs are no exception with the new fit for purpose rigs, we brought our costs down from about $6, $7 million Canadian down to, you know, we're down in that $4.5 to $4 million Canadian and we think we're going to get reserves at least in the core area in the -- greater than 5BCF per well, very attractive FND.

Are these drilling days reducing cycle times?

That's right. It is a fit for purpose equipment. It is some of the new completion technology that we're using as well. We're setting sort of record cycle times on these. They're fairly deep. Like I say, they're 2500 meter two vertical depth and then about 2,000 meters in length. We can knock these things off in about 20 days.

Okay. Jeff, one more if I may. What's the run rate in Omarosa these days, the gross run rate in terms of production?

The gross Omarosa field production has been over about 200 million a day.

Okay. Thank you very much.

Thanks, Tom.

Thank you. Your next question comes from Andrew Potter, UBS securities. Please go ahead.

Just a couple of questions on oil sands. First, you mentioned that you'll update us at year end on the oil sands plans and the expansion. Should we still presume the production profile you laid out when the deal was done is accurate or are there some forces that are making you want to go faster or slower? And second, if you can just maybe update us on the cost for Foster Creek 1D and 1E if there's any change from initial budgets or if that's still under control.

Hi, Andrew. We're more or less on track with the original forecast that we laid out in terms of production growth. There could easily be slippage of a year or so but I'm going to turn it over to John Brannan to more completely answer the question.

Thank you, Andrew. We've been working those production profiles and essentially, as Randy was saying, there are a few tweaks to them here and there. A phase may come on within a quarter plus or minus. On the Foster Creek 1D and 1E, we still expect those to be in that $13,000 per barrel range. Those are each about 30,000 barrel a day expansions.

Christina Lake, when it comes on, we expect the initial cost to be quite a bit higher than that simply because we have to build all of the initial infrastructure.

Sure. Perfect. Thanks.

Thank you.

Your next question comes from Benjamin Dell, Sanford Bernstein. Please go ahead.

Hi, guys. I guess my first question was around your refining and marketing business. Based on your guidance, on the increasing crack spreads, it would have suggested about a $240 million increase in your cash earning on the quarter and obviously you did significantly better than that with about 330. Just wondering if you could explain where the difference came from because obviously utilization dropped. I was wondering if there were any stock change gains in that number and if so, would they reverse going into the third quarter?

I'm going to turn that over to John Brannan.

Yeah, Ben, there were no unusual things in that second quarter. If you're making comparisons to the first quarter, when we put the deal together, January was kind of a down month because there were inventory adjustments in January so if you're comparing first quarter to second quarter, second quarter obviously looks better but there were no specific inventory adjustments or other things in the second quarter.

So if margins returned to first quarter levels, you would suggest that operating earnings would still be maybe up 100% on the first quarter numbers you had?

I'm not quite following your question there.

I'm just saying if crack spreads returns to the first quarter levels, you obviously generated about $95 million in income in the first quarter. Should we assume it is going back to those sort of earnings levels or should we assume it is going to be better than that?

It would be a little bit better than the first quarter because the month of January was down for inventories. So, on the third quarter, if the crack spreads were similar to what they were in the first quarter, our third quarter numbers would be a little better than our first quarter numbers.

Ben, we took approximately $100 million negative inventory adjustment in the first quarter.

Okay, great. A follow-up on unconventional gas price, can you give us some quick comments on Columbia River Basin and then moving to Europe, players like getting act of those looking in the Ukraine and areas like that around the tight gas price, big gas price. Have you looked at any of those or are they even on your radar screen?

Okay. For the Columbia River Basin play, we're in the process of drilling our third well in the play and we're intending to have a fairly complete evaluation done on that play by the end of the year and we probably would make some comments at that time. Regarding our work in Europe, we've investigated several countries in Europe where we could take our unconventional expertise and export it. We're looking for low risk areas such as countries that have a well-developed capital structure and rural law -- structure with respect to guest production such as France. We're looking at a few other places. The only one that has been talked about for us is Romania.

Okay. Just one last question, more of a macro issue, we talked about the rec. Is it your view that when it starts up and fails to capacity, that will be two BCF a day of new gas or incremental gas or you'll basically see some emptying out of other infrastructure and gas directed into the rec.?

I'll they are over a -- try to answer that.

We'll have to wait to see where those people have made the 1.5 commitment on Rex. That will be filled. What happens to the remaining pipes will, I guess, play it out. But we expect that we'll continue to have a continued production growth out of the Rockies, maybe not at the same level as we've seen over the last several years which has been at $500 million a day plus. So, we'll be watching with interest and taking positions on what we think are the premium markets to maximize our netbacks but it is something we're watching very closely.

We would think it would be highly unusual for all of the pipes in the Rockies to be filled instantly with that much additional take away capacity being added. But as bill says, you know, if the build continues at the rate that it has been historically, it wouldn't take that long before it became full.

Okay. Great. Thanks very much.

Thank you. Your next question comes from David Bentley, AllNovaScotia.com. Please go ahead.

Yes, I'd like to ask two or three more questions Deep Panuke front. Firstly, rather an easy one, are you satisfied with the progress on Deep Panuke or are there any negative issues emerging?

I'm just going to turn that over to Gerry. Gerry has been really on top of that.

Hi, David.

Hi, Gerry.

No, we are comfortable with the -- I assume your question was regarding the regulatory process and we are comfortable. We have reviewed the decisions and we are still anticipating that by the end of next month we would have a permeating decision on the project.

And I was wondering as well on the commercial side as far as how things are going on the bidding. Are you happy with the way that is going so far? I realize you haven't had the responses in yet, but -- .

I think that the information is getting out there and we are expecting kind of timely bids and we will review them when they come in.

Good, good. Secondly, I'm wondering if you see the decision by Exxon, Mobile and Shell to put their Deep Panuke interest on the market. Is there any sort of lack of confidence in the project or an indication that perhaps you might not be able to come to an agreement to use the Sable line to ship the gas ashore.

No, you would have to contact Exxon and Shell for their decision to sell their interest. We are aware that they are for sale, but we have no comment on them. We are the operator of the project and we are proceeding as we just discussed.

Do you think though, Gerry, that that may have any sort of a negative impact on whether you will be able to reach an agreement to use the Sable line?

I don't think it has any impact.

No, okay. Finally, are you able to say whether you would be interested in those interests that they have?

We don't comment on any assets that are available in the market place.

Right, thank you very much, Gerry.

Thank you. There are no further questions at this time. Please continue.

Well, thank you very much, everyone, for joining us today to review EnCana's second quarter results. Our conference call is now complete. Ladies and gentlemen, this concludes the conference call for today. You may now disconnect your line and have a great day.