Welcome to the EnCana Corporation’s third quarter 2009 financial and operating results and 2010 outlook. 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) I’d now like to turn the conference over to Mr. Paul Gagne, Vice President of Investor Relations; please go ahead.

Thank you, operator and welcome everyone to our discussion of EnCana’s third quarter 2009 results and our preliminary 2010 budgets. 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 EnCana’s operating results and turn the call over to Brian Ferguson, EnCana’s CFO and Cenovus designated CEO to discuss EnCana’s financial performance as well as Cenovus 2010 preliminary budget. We’ll then turn the call back to Randy to discuss EnCana’s 2010 preliminary budget and follow with some closing comments. Afterwards our leadership team will be available 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 we’ll highlight our performance in the third quarter of 20009 for EnCana and discuss the 2010 budgets for both the new EnCana and for Cenovus. I’d like to emphasize of these are preliminary budgets which Brian and I expect will be revised during the upcoming year as our independent business strategies mature and as we understand how the economic environment is unfolding. Before we get into the focus of today’s call I’d like to take the opportunity to update everyone on the timing of our proposed transaction. On September 10, we announced our plans to proceed with a plan of arrangements to split EnCana into two independent energy companies. We mailed out the information circular at the end of October and shares for both the two new companies began trading on a when issued basis last week. Shareholder vote is scheduled for November 25 and subject to shareholder and court approvals, the company expects to complete the transaction on November 30. I’m pleased to report that we’re on schedule and working diligently to insure a smooth transition over the upcoming months. Going forward EnCana and Cenovus will strive to be among the premier producers for their respective businesses while continuing their tradition of responsible resource development. Each Company will build its future on very strong foundations of quality assets, people, and business strategies. Now, switching to the third quarter operational results, in the third quarter we continued to see strong operational performance from our key resource plays. The lowered our operating costs, had strong well performance and improved our capital efficiencies. So, first for our gas activities, total quarterly natural gas production was about 3.6 billion cubic feet per day down 9% over the same period in…

Thanks, Randy. Good morning everyone. EnCana’s third quarter again posted strong financial performance anchored as Randy described by the strength of our operations. For the third quarter, natural gas prices averaged $3.11 per thousand cubic feet excluding our financial hedges representing a 64% decrease compared to the third quarter of last year while liquids prices also excluding our financial hedges averaged $57.40 per barrel, a 42% decrease compared to last year. This price weakness was substantially mitigated by our commodity price hedges. Our realized hedging gains were $3.39 per thousand cubic feet equivalent during the quarter adding after tax cash flow of $913 million. EnCana achieved cash flow per share on a diluted basis of $2.77. Our expected full year cash flow guidance remains unchanged at $10.10 per share on a diluted basis. What EnCana actually reports for the full year 2009 will include Cenovus for 11 months, so the full year numbers will require some interpretation for you. Our cash flow performance in the quarter was accompanied by operating earnings of $1.03 per share on a diluted basis, representing a decrease of 46% compared to the third quarter last year. The lower comparative results in both cash flow and operating earnings generally reflect the combination of low commodity prices and the large volumes of natural gas that were shut-in or curtailed. Our quarterly net earnings were affected once again by the combined impact of realized and unrealized hedging gains and losses, which resulted in an $18 million after tax decrease to net earnings in 2009 compared to a $1.8 billion after tax increase to net earnings in the third quarter of 2008. I believe that operating earnings are a better measure of our performance, because they remove the variability associated with the unrealized mark-to-market accounting accruals. Operating costs were…

Thank you, Brian. I’ll now discuss the 2010 budget plans for the new EnCana. So following the completion of the transaction, we expect EnCana to be the premier senior North American natural gas company focused on profitable growth from a strong portfolio of low cost unconventional natural gas plays. Our goal is to achieve strong long term operational and financial performance. We’ve initially set EnCana’s 2010 capital budget at about $3.6 billion to $3.9 billion. At this level of spending, we expect to achieve production of 3.2 billion to 3.3 billion cubic feet equivalent per day, about a 9% increase above 2009 levels. We’ve chosen what we believe is a prudent and conservative investment plan that allows us to generate sufficient free cash flow, to maintain our financial strength and flexibility during this time of continued financial uncertainty. Should commodity Markets as well as our delineation work continue to be positive, additional capital may be allocated to our new shale plays for additional land capture, retention and evaluations. The bulk of a 2010 capital is directed to growing production in our lowest supply cost plays as well as for the evaluation of our emerging plays primarily at Haynesville and Horn River. Our preliminary budget allocates $750 million and $350 million respectively to these two plays alone. Another $220 million is allocated to our Deep Panuke gas project, which is scheduled to come on stream in late 2010 or early 2011. In the Horn River we are beginning commercial development in 2010 and we expect to continue to drive down our costs to a more competitive level within our own low cost portfolio. As I mentioned earlier, we’ve seen excellent results in our Horn River play and we expect production to grow to about 55 million cubic feet per day next…

(Operator Instructions) Your first question comes from Brian Dutton - Credit Suisse

Brian I was wondering if you could give us a little more insight into your guidance for Foster Creek and Christina Lake production in 2010. I gather that the numbers you’re showing there are net numbers, but you’re also showing an effective royalty rate, but when you gross up those numbers to get it on a gross production basis and before royalties. The guidance you’re giving for 2010 looks somewhat like the current production?

Brian, I think we’ll let John Brannan respond to that. There’s a couple of moving parts here that explain it.

Yes, the guidance numbers that we have are on an NRI basis and our current production while close to 100,000 barrels a day at Foster Creek and around 15 at Christina Lake, those are kind of weekly averages, not annual averages or not monthly averages. We factor into our guidance about a 93% run time so, 7% or so down from that 100% number. The other thing is that our capacity at Foster Creek will be 120,000 barrels a day yet we won’t reach that capacity until we have some patterns on blow down so we would expect to maybe enter the year somewhere around 95 to100 and exit the year somewhere around 106 to 110, those type of numbers on kind of a monthly basis. I hope that helps answer your question.

I think John, I might also add the royalty component.

Yes, the other piece is currently before payout at $65 oil, we’re about 2.2% royalties on a gross basis and at $65 with the post pay out royalties would be 27.3% on a net basis and at current rates and current volumes and current oil prices we would expect that we could go into that post pay out at about the first of June.

So on a gross basis then if you were looking at your production for 2010, can you give us a feel us to what that 42 to 44 and 7 to 7.5 would be on a gross basis through the year?

Yes, I think at Christina Lake, it will be somewhere around that very close to that 7 to 7.5 at Foster Creek I think I’ve calculated that to be about 51 or 52, somewhere in there, 96 at a gross basis, so taking that on the EnCana share it would be 48.

It will be a lot clearer when they start reporting and using Canadian protocol next year.

Using NDR protocol.

Second question is just on the tax rate for Cenovus. You’re indicating here an 18% effective tax rate in 2010. Is that a normalized rate we should be looking at on a go forward basis?

It I guess is reflective, yes of the split of the operations as we look forward, recognizing that the U.S. taxable income is a smaller component forecast for Cenovus.

Your next question comes from Chris Theal - Macquarie Securities.

Just a question on cash taxes and the circular you’re looking at, about a $700 million cash tax expense. Do you see that in the fourth quarter and the $500 million recovery in 2010? Is that still looking like a reasonable number?

Yes.

Your next question comes from Amanda Frazer - AllNovaScotia.com.

I was just wondering if Deep Panuke economical what today gas prices?

When you look at sort of Deep Panuke on a go forward basis, it is definitely economic in today’s gas prices if you will, and that’s based on sort of our 650 long term price.

So what price then do you need to see to make the project economical in the long term?

Well like I say we run with about a 650 long term price and going forward we see Panuke very economic at this point.

There’s been talk before too that it’s a non-core asset for EnCana. So I’m just wondering I guess is EnCana looking for a buyer for the project in the long term?

The Deep Panuke project we’ve always expressed it as being the similar from all of the other projects that EnCana has been pursuing over the last number of years, our unconventional gas strategy, but we have not been actively pursuing the CLV assets. We’re comfortable keeping it in our portfolio as it is approaching production, but we’d also if the situation was right we would consider selling it as well.

Your next question comes from Barbara Betanski. - UBS Global Asset.

The question is related to the divestitures that you mentioned for Cenovus of 500 million this coming year and I’m wondering if you’re planning on continuing a divestiture program over a number of years and just looking at the balance you have right now between oil and gas, whether you think that’s an optimal balance are you moving towards a more oil leverage longer term or do you want to keep those mature assets as a source of free cash flow longer term?

Yes, we are going to be targeting about $1 billion in divestiture proceeds over the next two years. You are correct in that we intend continue to emphasize the oil opportunities inside Cenovus portfolio and expect over the next three to five years to see that if you look at it just on straight production waiting that we would be in the range of two third to three quarters oil weighted within that time period. I would emphasize though that we do not and I certainly do not think of our growth opportunities other than those focused on our oil and our bitumen projects. As I mentioned in the call notes, we have got a tremendous amount here with the free cash flow that’s generated from our shallow gas assets and I really think of them as a financial asset, not as a production asset.

Your next question comes from Peter Ogden - National Bank.

Just a couple of questions, just maybe building off the last question, you mentioned Cenovus wants to concentrate on its oil opportunities. Can you give some of the strategic rational behind the selling of Senlac in the quarter? Why you would have sold an oil property within Cenovus?

Peter, Senlac had very limited growth opportunities. It was a small property and we’re focusing on some very material growth opportunities on the other projects that we’ve got starting first and foremost with Foster Creek and Christina Lake and you should expect us to continue to focus on where we can have a material impact in terms of creating net present value as we go forward.

The second question involves the refining and the guidance surrounding that. You have $100 million to $200 million in cash flow, net of the $44 million LIFO/FIFO adjustment this quarter and you do about $50 million a quarter, I would argue would be a relatively weak crack spread and a narrow heavy oil differential. What kind of heavy oil differential are you assuming next year for that cash flow and I guess, what’s your macro view on kind of the refining next year?

This is John Brannan. Peter, what we are looking at is differentials in that 15% to 20% range and we think that they will be in that range kind of on a longer term basis. There is a number of refinery expansions that are all going on to heavy up refineries, when there’s less crude coming out of Mexico, less crude coming out of Venezuela and less heavy coming out of OPEC. So there’s a bigger draw and certainly pipeline capacities available to take the Canadian crude down into the Pad 2 and Pad 3 refineries. So we think for the midterm like three to five years, six years that we think those differentials will stay in that 15% to 20% range.

Once core is on production, that $100 million to $200 million, could you hazard a guess as to where that cash flow would go given the same assumptions once core is operational?

I think we definitely run a number of models there, but it is substantially higher than that $100 million to $200 million.

Your next question comes from Kam Sandhar - Peters & Co. Kam Sandhar - Peters & Co.: Just a quick question on what your spending levels are going to be looking like for the Montney and for Bighorn next year?

I’ll just let Mike Graham and Jeff Wojahn answer that question, because there’s a bit of variability in both of those depending on how commodity prices respond and how we see the economic environment turning out.

Kam, you’re asking on the Montney and Bighorn. This year in the Montney, we’re actually drilling in the order of about 52 wells, what we have planned for 2009. We’re probably going to be in that similar sort of range next year. So we’re talking in the tune of about $400 million to $500 million of what we’ll be spending in the Montney. A quick update on the Montney, similar to the Horn, we continue to drill our wells longer and putting in bigger fracs upwards of 2500 meters in some of our latest wells and we’re getting some tremendous rates out of the Montney. Some of the wells are coming on over 10 million cubic feet a day now and we do think our EURs are going up as well in the Montney. We think we can have wells as much five to even close to 10 Bcf per well in some of our core areas in the Montney. So the Montney looks very, very attractive. We have a big, big land position somewhere in the order of 700,000 net acres in there. So we’ll spend sort of accordingly in the Montney. Moving into Bighorn, Bighorn is what we call the Deep Basin of Alberta. We have about a thousand sections on that property and very good results again in Bighorn. We’ve decreased our capital on the well from about $5.5 million down to about $4.5 million per well, so very economic. So we’ll probably be doing somewhere in the same order in Bighorn next year as what we’ve done this year, maybe even a little bit more in the 50 to 60 well type thing, so again about $300 million to $350 million in the Deep Basin of Alberta.

Your next question comes from Richard Wyman - Canaccord Financial.

Just a couple questions here, one follows on the last one. Could you comment on out of the Cutbank Ridge business unit? How much of the production is Montney sourced? Then the other question I have is of the capital efficiencies that you’ve achieved this year. How much permanent do you think or maybe just illusive during a period of cost deflation?

Mike Graham here again. On the Montney, we have currently about 180 million cubic feet a day coming out of the Montney, somewhere in that order and obviously the big growth going forward in the Cutbank area is going to be out of the Montney, if you will and if you look at sort of deflation if you will for this year 2009, we think it’s somewhere in the 10% to 15%, maybe even up to 20% in some of the cases. Randy alluded to it on some of his notes there that costs have come down a lot. Mike McAllister, who actually runs the business unit, thinks with can get our costs in the Montney somewhere less than 650,000 per interval and we might even get into half a million dollars per interval and time goes on and we’ve seen that in some of our latest wells. So the Montney continues to be top quartile in our portfolio.

What about broadly over the company of the cost efficiency improvement, how much is attributed just to surplus oil field services and price competition versus operating efficiencies driving the cost down?

Richard, what we do is we try to at least offset inflation each and every year with efficiencies and if you look at the fit for purpose rates the fracking technology, we seen substantial improvements in costs, like we say the Montney is down 70% to 80% over the last four or five years. We think we haven’t reached sort of the peak of that yet and we’ll get more cost efficiencies as we go forward. Inflation is probably around zero for next year and 2010 is what we’re looking at in the Canadian Foothills.

On the Horn River budget of $350 million, how much of that’s drilling and how much of it is infrastructure facilities and stuff like that?

Richard, in the Horn River like this year we drilled like I said about 21 net wells in the Horn River and again, our costs are moving down quite a bit. We’ve gone from about $3 million to about $2.5 million in drilling for our days have gone from about 30 to somewhere around 60 in days. So we’re just seeing tremendous cost efficiencies and we really do try and load level our program in the Horn River. So this year we actually spent a lot more money just drilling wells and kind of load level. We actually only put on four wells in 2009 and that’s kind of what we’re planning for 2009. You’ve seen the results for 12 to 14 fracked wells. We’re coming on in the order of 10 million cubic feet a day. So for next year, a lot of our capital is going to be spent on completions, ourselves and our partner Apache we’re gearing up to start completing wells. We have well pads anywhere in the order of 10 to even up close to 16 wells on a pad and we’ll just kind of load level those then and complete as we go, so drilling I would think would be similar to sort of this year and say, we’re targeting about 21 sort of net wells if you will and a little bit more on the completion side for 2010.

I think the plant construction capital is more in the 2011 time frame?

Yes, that’s right Randy.

So there’s significant spending on that one next year.

Your next question comes from Ross Payne - Wells Fargo.

I wanted to just ask a question, How far down in terms of sales of gasses as you want to go far enrich your natural hedge, or how do you think about that?

So I think you’re talking about Cenovus, and I’ll turn that over to Brian.

Right now in terms of our internal consumption, at current production rates at Foster Creek and Christina Lake we consume between the refineries in Foster Creek and Christina Lake about 100 million cubic feet per day and we expect that to continue to increase overtime as we continue to grow our SAGD production and that will take us up into the 200 million to 250 million cubic feet per day range. Certainly, the divestitures that we have planned over the next couple of years, we would still have a belong natural gas production as such and again these are, I would characterize as extremely valuable assets because of the very shallow decline predictable nature of the asset and very high netbacks relative to most of the rest of the industry because of lower royalties and low operating costs so we don’t have any kind of a plan to divest of all of the assets. It’s really focusing on those that we would consider non-core that are maybe higher operating costs or the higher decline, those sorts of things in terms of how we continue to high grade portfolio as we go forward.

Your next question comes from Mark Polak - Scotia Capital.

Just a question with the wider well spacing in the Horn River, I believe you’re trying 300 and 350-meters, just want to confirm that and I’m curious if you think there’s potential committee even go to maybe even go wider than that at some point and then second part of that, is that something you would look at trying out in the Haynesville or Montney or do you feel you have the spacing optimized in those other regions?

I think there’s a given opportunity for Jeff to come on line a little bit later and give you updates on the Haynesville.

Yes Mark, we are definitely going to sort of wider well space and we’ve gone from about 200 which is essentially eight wells per section, we’ve increased that to 250 and some of our latest pads we’re going up to 350 even close to 400 on those. We are drilling our wells longer. We’ve gone from a thousand to 1,600 meters, our latest couple wells are out as far as 2,200 meters and so we’re a long ways on the horizontal. We continue to look at our fracs and the tonnage, we continue to do about somewhere in the order of 200 tons per interval and we’re looking at sort of sand tonnage as well. So we have a huge inventory, like I say we have about 250,000 net acres in the Horn and we probably have a drilling inventory somewhere in the order of a couple thousand net wells just ourselves without our partner Apache. The Horn River between the sort of the three Devonian zones, are Musquash, Otter Park and Kahlua are the easiest as we got a tremendous amount of gas in place from 150 to right up 250 plus Bcf per section, so we are doing a lot of experimenting on sort of the length of our wells, the size of our fracs, our frac spacing and I think it would be fair to say that we’re doing a lot of that in the Montney as well. Like I talked about recently, we drilled wells as long as 2,500 meters in the Montney, and we’ve gone from four to eight and now Mike is fracking right up to as many as 14 stages per well. So this thing is moving quickly and I think Jeff will tell you the same thing in the Haynesville. We haven’t quite figured it out and really it’s driving a lot of the efficiencies. It’s driving a lot of the great well results have it be at the Horn or the Haynesville or the Montney.

So I’m going to have Jeff comment as well. Jeff is not with us today. He’s in our Denver office, so Jeff if you’re still there?

Yes, I am. Thanks, Randy and thanks Mark. One of the competitive advantages I think of EnCana is we have a breadth of technical knowledge that we share. In fact we just had the Horn River team down in our Texas office to talk to our folks that are working on the Haynesville and the Barnett to kind of compare notes and we do that daily, monthly, weekly, within the teams. So when you hear about 2200 meter lengths or 300 foot stages or more stages, you can be assured that our technical teams are sharing learning across the company. So that’s my first comment. We have a high technology transfer. In regards to the Haynesville specifically, we buy and large have been eliminating the length of the wells to fit within the sections as part of our land retention strategy. So we haven’t really been doing the experimentation say that the Horn River team has been doing by drilling 2200 meter horizontals. It’s not technically something that we couldn’t do, but at this point, we’re focused on remaining within our land retention strategies. So we’re doing other things and those things are around optimizing spacing, fracture spacing, playing with our gel loads, trying to make sure that our run time efficiencies of our pump jobs actually come off effectively, so that we don’t break equipment because of the high breakdown pressures we have in the Haynesville. Looking at optimizing the type of profit we use, all of those kinds of things we’re experimenting with and generally what you’re seeing is a little bit higher gel loading, a little bit higher concentrations of sand, little higher concentrations of water and they’re incrementally improving the performance on a per stage basis. Like what Mike has said, we continue to evolve that and there’s no doubt in my mind that over the last 16 months, we’ve been on a rapid technological improvement around optimization of our completion programs and cost structures of these plays.

Maybe just one follow-up for Mike, is it just an optimization sort of analysis in terms of a lower drilling costs versus higher fracking costs as you go for more tonnage or do you reach a practical limit of how wide you can get even with more tonnage and where you lose communication and you’re not quite filling in the space between wells?

That’s exactly right Mark. We’re doing a lot of experiments just to figure out the best way to recover the most reserves we have, we can get on them and similar to the Barnett you’ve seen recoveries going from 10% to 20% to 50% recovery factor in places in the Barnett and hopefully that will be the same in the Horn River. So like I say we’ve got a big, big inventory, and we’re just experimenting quite a bit ourselves and Apache our partner there and we’re very pleased with the results. So we are putting in bigger fracs, we’ve gone right up to 300 tons per stage and we think we’re probably appropriate in that 200 maybe even a little bit less than that and we’re just experimenting on the spacing and what kind of recovery we’re going to get up.

Your next question comes from Carrie Tate - National Post.

I’m looking at the IEA report that came out earlier this week that looks like there maybe a gap. Their prediction is there will be a gap until 2015. What would happen to EnCana if this proved correct?

We do expect that there to be, I’m not sure I want to use the word a gas glut, but we do expect that natural gas is going to be in abundance for a very long period of time. EnCana is very well positioned with as very low cost structure and exposure to significant development opportunities within many of the lowest cost plays in North America. So despite the fact that we have a lot of gas, EnCana is positioned very well to succeed in this environment. Should that gas glut, I guess deteriorate and prices improve, EnCana would do even better.

When you say that you think there will be in abundance for a very long time, how long is a very long time?

It’s really a question as to how much incremental demand is created in North America. What we know there’s determined is that the supply of natural gas in North America at current production rates appears to be in the order of 100 years in length so, that’s a very, very long time and that’s the gas availability using today’s technology, so we think with future technology growth that abundance could even in terms of time could even be higher. We believe strongly that natural gas has a role to play in increased demand in North America both in greater use of natural gas for electrical generation and also we believe it has an opportunity to displace gasoline and diesel in the transportation sector. So it really is a question of how much opportunity is taken up in growth of new natural gas demands.

Right now when you talk about your low cost projects which ones would take priority given a continued abundance situation?

Today we have quite a few plays which are demonstrating very low cost what we call supply costs and we also see several plays that have the opportunity in the future to be among the lowest supply cost plays in North America so it’s a combination of plays that we already have and developed in our portfolio such as our Jonah play in Wyoming, our Deep Basin in Alberta, our Cutbank Ridge play in the Montney play in both Alberta and British Columbia and then we also see that the Haynesville is likely to get into the lowest cost structures as well as the Horn River eventually.

Your next question comes from Scott Haggett - Reuters.

I’m wondering with your shut-in volumes is there a price point at which they will return as always that return of those volumes now fixed?

We did those gas volumes when the prices we were exposed to were generally in the $3 range and our plan right now is to start bringing them back on stream and they will be brought back on stream over the course of this winter. Our expectation is that there will be some Form of correction in prices of next year, but the price we’re currently seeing in above the $5 range and its $5.5 is a strip for next year are adequate.

Are you looking at the Marcellus at all are you planning an entry next year or in the future?

We have been watching developments in the Marcellus play and we have a small entry position, which we hope to learn more about the play over the course of the next couple of years.

Your final question comes from Pat Roesch - Daily Oil Bulletin.

I notice you’ve dropped the use of the word oil sands it seems to me you’ve dropped the word oil sands entirely and instead you refer to your SAGD projects as enhanced oil projects. Wonder if somebody could talk about the rationale for that?

Really what we have done as have a look at the nature of the recovery techniques that we apply and on EnCana’s bitumen production which is 100% SAGD there are assets and properties that we drill and use drilling techniques to recover the oil, which is really a Form of enhanced recovery which the industry has been focusing on for many decades and we just thought it was more representative of the nature of Cenovus assets to describe them as such so that there wasn’t any confusion about that.

That’s confusion between in-situ production and mine. Do you think that the Alberta government should follow and make a clearer distinction between in-situ production and mined oil sands?

I think that’s we’re happy to respond to questions that relates specifically to EnCana or Cenovus that’s probably a question you should maybe direct-to-cap or to the government.

There are no further questions at this time. Please go ahead Mr. Eresman.

Okay, well, thank you everybody for joining us today for our third quarter conference call and our conference is now complete.

Thank you everyone for joining us today to review EnCana’s third quarter 2009 financial and operating results. Our conference call is now completes.