Good day ladies and gentlemen and welcome to EnCana Corporation's first quarter 2010 results conference call. (Operator instructions) Please be advised that this conference call may not\ be recorded or broadcast without the express consent of the EnCana Corporation. I would now like to turn the conference call over to Mr. Ryder McRitchie, Vice President of Investor Relations. Please go ahead, Mr. McRitchie.

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

Thank you Ryder and thank you everyone for joining us today. Today’s conference call will highlight our strong performance in the first quarter of 2010 and reiterate the rationale for EnCana’s new high growth strategy. During the first quarter of 2010 EnCana continued its focus on maintaining or improving margins to deliver growth and shareholder value despite low natural gas prices. Cash flow for the quarter was approximately $1.2 billion and operating earnings were $418 million. In the first three months of this year we invested just over a billion dollars of our planned 2010 $4.5 billion capital program. This capital investment was worked to advance the development of several of the company’s key and emerging resource plays while at the same time generating strong production growth. Our first quarter total production of approximately 3.3 Bcfe/d is inline with our full year 2010 guidance and we’re well positioned to achieve our expected exit rate production capacity of between 3.4 and 3.5 Bcfe/d. This morning I’ll start with the Canadian division results before moving on to the results for our USA division. In Canada we invested approximately $543 million this quarter towards advancing the development of our key and emerging resource plays including the Horn River, Montney, and Deep Panuke. Canadian division production for the quarter was approximately 1.3 Bcfe/d down 9% from this time last year due to divestitures that occurred in 2009 and early 2010 as part of our ongoing portfolio optimization program. However this decline was partially offset by a very successful drilling program at our Bighorn key resource play as well as lower royalty rates seen in our Canadian divisions. At Bighorn we brought on 20 million wells during the quarter and our wells in this area have been outperforming our tight curves and as a results,…

Thanks Randy, and good morning. EnCana’s 2010 first quarter financial results were very strong. Cash flow for the quarter was about $1.2 billion or $1.57 per common share diluted, down approximately 15% from the first quarter of 2009 on a pro forma basis. Despite year over year production growth and stronger natural gas prices this relative decrease in cash flow is largely attributable to EnCana’s exceptionally strong 2009 hedge position that led to higher netbacks last year. At this time last year EnCana had approximately 50% of its total expected natural gas production for the remainder of 2009 sold forward at a NYMEX price of about $9.10 per thousand cubic feet. For the first quarter this year EnCana’s hedge position contributed a realized after-tax gain of approximately $125 million. For 2010 we currently have about two Bcfe/d hedged under fixed price contracts at an average NYMEX price of $6.01 per thousand cubic feet. Additionally EnCana has hedged approximately 935 Bcfe/d of expected 2011 natural gas production at an average price of about $6.52 per thousand cubic feet and approximately one Bcfe/d of expected 2012 natural gas production at an average price of $6.46 per thousand cubic feet. Having these hedges in place increases the certainty of our cash flow generation by providing downside protection from low commodity prices thereby ensuring stability for our capital programs and dividend payments. EnCana’s hedging requirement, EnCana’s hedging arrangement are with a diversified group of approximately 20 different counterparties with strong investment grade credit ratings. Operating earnings for the quarter were $418 million or $0.56 per common share diluted, down 22% year over year on a per share pro forma basis. Net earnings for the quarter were approximately $1.5 billion or $1.97 per common share diluted, up by more than 200% from last year on…

Thank you Sherri, overall we have a very strong quarter, with average production for the quarter at approximately 3.3 Bcfe/d, we’re on track to meet our 2010 production guidance and our forecast exit rate. We’ll continue to plan and invest for the long-term and we’re confident in our ability to reach our goal of doubling the company’s production on a per share basis over the next five years. EnCana has an enormous asset base that we’ve built over the past decade. We have identified an estimated 12.8 trillion cubic feet equivalent of proved reserves plus another 16 trillion cubic feet equivalent of low estimate economic contingent resources using forecast prices. Affiliated with these resources are 23,000 net drilling locations which equates to many years of organic growth opportunities. This reserves and resource base has been evaluated externally by independent qualified reserve evaluators, the gold standard for reserve reporting. Given the size and quality of assets that EnCana now has in its portfolio assets that we expect can be economically produced at very low costs, assets that on average provide a cost of capital return even at a sub $4.00 gas price, value creation will be most readily achieved by way of an accelerated development plan. Our gas [factory] approach to the development helps to ensure that while we’re continuing to strive to optimize operating efficiencies and reduce costs, we’ll also be in a strong position to grow production profitably through the price cycle. So as we look forward to the remainder of 2010 we see the potential for continued downward pressure on natural gas prices. Accordingly we will watch market developments and where we see continued or longer term weakness in the natural gas prices we will act to preserve value. This may include a similar curtailment strategy to what…

(Operator Instructions) Your first question comes from the line of Greg Pardy – RBC Capital Markets Greg Pardy – RBC Capital Markets: Do you still have any natural gas shut in at this stage.

We have a small quantity shut in in the Dawson area.

We have like 25 million cubic feet a day shut at the end of the quarter and we should be bringing it on over the next quarter if you will. Greg Pardy – RBC Capital Markets: We know you’re a gas company but will you or would you pursue any oil opportunities on your lands.

Absolutely, we’re not adverse to producing oil, and we certainly like liquid rich gas when we find it and so we will develop it on our existing land bases and we will continue to look for it as long as its in conventional reservoir types. Greg Pardy – RBC Capital Markets: With the Canadian dollar having appreciated that’s obviously going to have an impact on your Canadian cost structure but could you talk a little bit about that as well as how you would be thinking about the development of the Horn River given what’s gone on with the dollar and just costs and so forth, is the focus on growth then really going to be in the lower 48 and does Canada trail that or how are you thinking about it.

We’re going to continue to focus on what we think is a more sustainable long-term natural gas price for our development plans and its times like this where we take the opportunity of lower cost structures that might develop as a result of reduced activity. I think it more than offset what’s happened with the Canadian dollar against the US dollar. On the other hand the higher Canadian dollar also in the longer term will give you better buying power for the international commodities that are US dollar based. So we’re going to be pretty steady in terms of our development plans in the Horn River and Montney and Coalbed Methane.

The first quarter the Canadian division we had sort of a shut in strategy coming out of the quarter and we produced about 1258, also we sold about 100 Bcfe/d in 2009. We exited the quarter at about 1.4 Bcfe/d so our production is up quite nicely over the end of the quarter if you will and we expect to exit the year about 1.5 Bcfe so we’re still seeing some pretty strong growth out of Canada. Greg Pardy – RBC Capital Markets: How big does the Horn River get for you whether its an average or an exit rate for this year.

Presently we have very little volume, we’re just starting to bring on an Apache pad at the moment, so right now we’re about 20 Bcfe/d. We expect to do about 55 Bcfe/d for the year and we expect to exit the Horn River right around 100 Bcfe/d net to EnCana and 200 Bcfe/d at the end of 2011.

Your next question comes from the line of Brian Dutton – Credit Suisse Brian Dutton – Credit Suisse : I was wondering if you could give us a little more color on your thoughts here on the liquids content in your US natural gas production and how you see that unfolding as we move forward here through the year.

Where we have liquids rich gas we have opportunities to accelerate the development, of course we would be pursuing that as it gives a tremendous lift to the returns on natural gas plays today and I think you’ll see that emphasis across most companies operating in North America. Now the number of opportunities we have, we have a few in the Rockies, and we have some liquids production in our Barnett shale play. And we’re working on a few other ones right now.

If you’re referring to higher net back prices then NYMEX, and there’s a number of factors associated with that and one is that we would be selling more of our gas down Rockies Express pipeline and receiving premium pricing in the Clarington market, you may also have noticed that our transportation costs are higher to reflect that as well. But overall we’ve also seen a great decrease in differentials in the marketplace as Randy talked about earlier. So when you add those things up, you see that we have an uptick of what we noted as $0.23. I wouldn’t say its been because we’ve targeted a different strategy but its just a reflection of the conditions that we have.

Your next question comes from the line of Andrew Fairbanks – Banc of America Andrew Fairbanks – Banc of America : Just curious as you roll out the gas factory approach across the asset base if its possible to quantify what kind of cost benefits you expect versus say the first quarter levels, is this worth 3 or 5% in terms of unit cost reductions in real terms or do you have a set of expectations that would be reasonable to look forward to.

I’ll try to answer that as best I can using some of the historical references, two years ago I think our average portfolio supply cost was about 5.50 thereabouts, and that had been creeping up over the years. This year its dropped down as low as $4.00 and that’s been in basically a two year timeframe. We’re seeing a number of plays now that look like they can get sub $3.00 and so I think its conceivable over time if you didn’t change, if there’s no change to costs of services. So there’s no inflationary effects, it is conceivable that it could get down as low as $3.00 at the time.

Your next question comes from the line of Mark Polak – Scotia Capital Mark Polak – Scotia Capital : Just a bit of follow-on to Greg’s question I think in January you had about 125 million shut in at that point and 25 million shut in now is it fair to assume there was about 100 million a day of contribution from shut in volumes coming back on in the first quarter.

You’re right in the shut in volumes like when we actually targeted the shut in and we brought on, but I know within the Canadian division anyway we did have some sort of unplanned maintenance if you will so we had a bit of erosion problems which forced us to shut in quite a few wells. And a lot of that wasn’t on, but it is on at the end of the quarter, so instead of doing the 1250 at the end of the quarter we’re actually about 1.4 so we’re up about 150 million cubic feet a day at the end of the quarter. So volumes are coming on pretty good. So yes some of that volume has been brought back on. We’ve got about 25 million a day shut in and it will be brought back on over the next quarter. Mark Polak – Scotia Capital : Was there any in the US, shut in impact.

Absolutely, we had upwards of 200 million a day shut in last year and we brought all those volumes on and when you look at our key resource play information you see East Texas and the Piceance basis having very strong increases in volumes and those are all related to shut in volumes coming in, so I estimate that over 100 million to 150 million a day of our first quarter production was related to specifically to bringing shut in volumes. We did bring a number of the Jonah Field and some of the Rockies in earlier in November back on but specifically in the Piceance and the East Texas you see the impact of bringing all those wells on.

And I might say that the strategy we employed last year and it fortunately worked out quite well for us because we typically shut in the wells when the price was sub $4.00 and we brought it back on as it approached $6.00, so we made a pretty good trade. And the same sort of thing we’ll be looking at this year if we see if there’s opportunities to delay production coming on stream or even to physically shut in as prices get sub $4.00 again. Mark Polak – Scotia Capital : It looks like pretty low cash taxes in the quarter suspect largely due to the tax acceleration you had last year from the reorganization, just wondering how you’d expect cash taxes to look the rest of the year.

Actually based on our current guidance we really estimate a modest cash tax recovery for 2010 so things look pretty good there in light of the transaction.

Your next question comes from the line of Mark Gilman – Benchmark Mark Gilman – Benchmark: I wanted to go just a little bit further on the liquids rich gas issue, does it make sense at all to consider given what you’re intermediate to longer term price views may be to stripping it out, it would seem that perhaps the value might be even greater if you do that.

Absolutely right, where we have the opportunity to do that in this environment it’s a far better proposition to take as deep a cut as you possibly can. And where we have the opportunities to do that I know our guys are working on that.

If I could just talk a little bit about the Deep basin, the Deep basis of Alberta has a lot of liquids rich gas and we are looking at that and like Randy alluded to we can leave it in our gas stream or we can run it through our refrigeration plants and take the liquids out so there is quite a bit of potential in Western Canada along the Deep basin and we’re looking at that.

And if you look at the future too in terms of having higher than a 10 to one ratio between liquids and gas it does make a lot of sense to cut as deep as possible. Mark Gilman – Benchmark: Any update on the exposure activity in the Haynesville that you might be able to provide since the analyst day and is it possible or are you looking at all at multilateral completions in the portion of the play where both the Haynesville and the Bossier might very well be attractive to complete.

I’m not sure what exposure means, what did you mean by exposure in the Haynesville. Mark Gilman – Benchmark: I said Bossier.

We heard you wrong, sorry about that, with respect to multilaterals whether they’re combining two different horizons together or whether they’re multiple laterals out of single well bores these are all the kind of optimizations that you could imagine that we’re thinking about as we move to further lower the supply costs in these zones. First action of course is to retain as much land as we possibly can in the Haynesville so it doesn’t allow you to do a whole lot of optimization at this stage of the game. But as a significant part of our land does have, the mid Bossier sitting on top of the Haynesville, there is going to be opportunities to have those types of completions. There’s a huge part of the Montney that also has, upper and lower Montney as well as some middle Montney so there are those kind of things. Historically we have tried multilaterals off of single well bores in the past and in some places we’ve mastered it but this is now, would be combining a lot of technologies at one spot so it would be something we try but we’ll be moving forward carefully. But you can imagine the cost reductions that could potentially occur by using it. Mark Gilman – Benchmark: Yes, that’s why I was asking Randy.

Your next question comes from the line of Brian Singer – Goldman Sachs Brian Singer – Goldman Sachs: Do you have any update of any activities in the Maverick basin.

We originally had partnership arrangement with TXEO, he went through Chapter 11, Newfield is our new partner. We’ve just completed our first well with Newfield, 5000 foot horizontal well in the Maverick basin and we’re looking at evaluating that so I don’t really have any news specifically other than we are conducting operations and we’re evaluating our land base. Brian Singer – Goldman Sachs: The second question is around the optional $500 million in extra spending you’ve highlighted how much certainty to you have around that and given that gas prices have fallen since your analyst meeting, what price should we look for in order for us to get a little bit more certainty that you’ll probably move forward with that.

We’re really seriously thinking about moving ahead with that and the money largely targets moving to gas factories in places like the Haynesville and so they’re demonstration of what the future might be so I think its pretty important that we get one done this year, or at least get one started.

Your next question comes from the line of Peter Ogden – National Bank Financial Peter Ogden – National Bank Financial : Just a quick question regarding your guidance from I think it was March 16 and maybe if you can give some color on how we should think about production in Canada and the US over the next few quarters just given that you’re producing 3.3 Bcfe/d, your guidance is 3.3. I have a negative rate in Canada of 1.4 to 1.5 and should US production actually decline from Q1 levels given that you produced at 1950 and your guidance is 1875 but we’ve got all this growth in the Haynesville, so just maybe some color on Canada and the US and how we should think about the gas production growth over the next three or four quarters.

One of the things we did as you know in the first quarter we brought back on a lot of the gas that had been shut in or had been delayed in terms of the production, so you would expect that there would be a bit of a flush production effect there and so without anything else, other activity, expect that the next quarter could easily see production fall off a bit. But of our increasing of our activity over the course of the year, I think that’s going to be somewhat muted. Now we are having some, an early break up in Western Canada which is going to cause some delays in activity for a while so we try not to look too much at quarter by quarter and we try to focus on the long-term. I’m just trying to tell you that there are a number of moving parts here. One of the other things is that we’re still debating as the possibility of where we would consider shutting in some gas so that might have an impact on full year numbers and exit rates. So I started thinking about to present it properly and rather than talking about exit rates specifically I think it may be more important that we talk about the production capacity that we’re building in the company. And so the 3.4 to 3.5 is more of a reference to production capacity. There is a lot of things that might happen during the year that might make us want to actually produce less. Peter Ogden – National Bank Financial : So that would be kind of managing some shut ins and just depending on where gas prices are.

Yes, there’s that effect and as Mike mentioned before we sold about 100 Bcfe/d of gas last year and this year I’m not sure what the annualized number is but we’re on track to sell something like 50, 60, 70 million a day, something like that, annualized for the year so that will start coming out of production probably more effecting the second half of the year than the first half of the year. So we also have to keep that in mind and then the other thing at investor day I focused on our capabilities to double production of the company over the next five years. I didn’t want to confuse it with talking too much at that time about doing it on a per share basis because I wanted to demonstrate that our company had the capability to do that. The reality is the way we manage company is the way we’ve always managed it and the way we’ll expect that we’ll manage it on a go forward basis is whenever we sell [inaudible] producing our cash flow generating assets, we’ll take a significant amount of that extra revenue and use that to buyback shares to keep us whole on a production per share basis. Peter Ogden – National Bank Financial : Your share buyback is obviously ahead of your disposition schedule, would there be a circumstance where you spent more than $500 million buying back shares.

Last year we positioned ourselves to split the company, we sold something like $1.2 billion of assets and I believe that we didn’t buy back any shares at all last year and our net divestiture program was 800 or 900 million, something like that anyway, so we don’t think of the company on a one year basis. Its an ongoing process.

We could see that would end up buying back more shares than earned dispositions but basically what we’re targeting is that any of the proceeds from our dispositions we’ll look to buyback shares if that makes sense at the time and we also on that front have bought back more at this point in order to preserve our annual per share metrics.

And we also have $2 billion of cash on the balance sheet. Peter Ogden – National Bank Financial : What do you see the production capacity of Horn River maybe at the end of the year being.

I mentioned that earlier, but we do expect to exit the Horn River at about 100 Bcfe/d net to EnCana and we have a 50% partner in Apache so between them and us we should exit at about 200 Bcfe/d gross.

Your next question comes from the line of Richard Wyman – Canaccord Adams Richard Wyman – Canaccord Adams : Couple of questions, one relating to the Op cost and G&A unit production basis, its below guidance and I’d like to get some sense of how durable that is versus what your guidance is and in then in a somewhat related way you talked about some concern now that inflationary pressures are working its way back into your capital programs, and I wanted to get a flavor for how you see managing inflationary pressures or use of oil field services versus satisfying your growth objectives and potentially doubling the size of the company over the next half decade or so.

There’s a lot of answers in those questions, the inflation that we’re seeing seems to be focused in a couple of areas right now. One is in steel prices as worldwide economic recovery occurs, increasing demand for steel is driving up costs. We manage a steel desk and I think for this year we largely have our steel purchased so that won’t effect us this year. That would be something that starts coming into future years. We have contracted a lot of our services for this year and so generally speaking we know what our cost structures will be but we still are exposed in future years for certain things. We have undertaken over the last number of years longer-term contracts for fit for purpose drilling equipment. That to some degree protects us as well. Now the other area that we’re exposed to is of course we do use and awful lot of energy in our operations. It comes in around, between operating and capital programs, we believe it something its something like 15% of our total spend and that’s largely diesel price and so there is some natural hedging that occurs with that because of our own liquids production. And Sherri is going to talk a little bit about the operating G&A.

The $1.02 itself was basically driven by higher volumes and lower LTI costs for the quarter. What we have been experiencing as well is the, we explored at investor day, was the continued decrease in our operating costs across our opportunity and portfolio of opportunities. So we’re continuing to see that materialize.

And one of the things on the longer term for what inflation typically does is it translates into higher commodity prices over longer term periods and so there is a natural, your margin can be maintained in an inflationary environment but I wouldn’t want to count on that and we see the best way to manage inflation is by continually inputting operational efficiencies and we know that what we’re currently experiencing some of the highest inflation, or expect to see some of the highest inflation which is on the pumping services side. That’s an area where we think some of the greatest optimization could also occur in the future. Richard Wyman – Canaccord Adams : So just to be clear here, on the G&A and Op cost at $1.02 notwithstanding maybe some unique qualities in the first quarter and your guidance of something that’s about 18% or so or 20% higher than that, how realistic is it to be thinking about something different than guidance and something more like you just recorded.

We think that will probably in the end be down a bit but we’ll make that reassessment as we look at our production guidance probably into the second quarter as well.

There’s a number of mark-to-market impacts in there as well that are really hard to predict. Richard Wyman – Canaccord Adams : Can you, with regard to this inflationary pressure can you quantify what sort of percentage change you’re experiencing and—

In the first quarter in the US we had less than 1% inflation in our activities so we’re not being impacted today. Its more of a function that we see the storm clouds coming and my supply and management people have advised us that they expect to see an overall increase in steel prices of 6% to 8%. Now as Randy mentioned the majority of our [inaudible ] goods are steel products, have already been acquired for the year. We estimate between 85% and 90% in the US has already been acquired so, its coming. On the completion side we see a great deal of activity obviously in some of our key areas, Haynesville being one and we see a high demand for completion services and so we’re in this situation where a number of the pumping services companies worked at very low cost structures last year to keep their crews busy. Today they’re seeing higher demand and they’re asking for increases so we’re working through that right now as it unfolds. So those are the areas of pressure as we see them today. Richard Wyman – Canaccord Adams : And from the pumping services perspective what sort of increase in pricing are you experiencing.

Its interesting because in the quarter I was looking at some of the bigger pumping services companies and what they were saying in their quarterlies and what they’re saying is modest increases in pumping overall but they’re certainly less than 10% today, but its really the function of demand as well. Richard Wyman – Canaccord Adams : And what about on the Canadian side of the border.

Well in Canada rigs are still, the rig fleet is still probably running at 50% capacity so we’re not too terribly busy in Canada. Like Jeff says we do have some pressures on pumping and steel like everybody else but what the increase like Randy talked and the Canadian dollar we actually have a bit stronger buying power. So essentially we’re pretty flat on inflation. If you look at our operating costs though most of the big gains have come in the US and our operating costs in Canada are essentially flat year over year on a Canadian protocol but because we report in US protocol we’re actually up about 20% and its all due to FX. Richard Wyman – Canaccord Adams : And maybe to wring the last bit of this out, let’s say at Horn River you’ve got a certain number of frac crews going and a certain number of rigs going between yourself and Apache and you’re going to get a production growth profile this year, what additional services do you need to bring to bear in that play as an example to go from 100 million a day to 200 million a day net to yourself a year and a half from now.

The Horn River is a good example. Randy talked about where our costs continue to come down and we’ve gone from about a million dollars to frac per frac on a capital basis to we think we can get down to about $500,000 on a per frac basis. And we think these wells may recover as much as 800 million to Bcf per frac so it brings your F and D at least on a per well or a per pad basis down somewhere below $1.00. So that’s just efficiencies we get from that. And a lot of that has to do with pumping services. Randy talked about we have a lot of fits for purpose drilling rigs. So we’re not as efficient as we can be in Canada especially on the pumping services. I think they do a lot better job in the US but now that we’re going to these big 16 well pads and we may be putting 20 fracs per well, we might be up to close to 400 fracs off one pad and we’re doing two to three to sometimes four fracs per day, we’re going to see a lot of efficiencies yet to come in our fracturing and our pumping services. So we are getting a lot better at it and we’re taking a lot of lessons from how the US are doing it. Richard Wyman – Canaccord Adams : So are you going to require more services, that was part of this question.

Not a lot because if we can just run one or two frac spreads, we’re in pretty good shape in the Horn River. In the Horn River today we’re only running two rigs or 2.5 net rigs and we can add a tremendous amount of production even with those few rigs running because it is a true gas factory if you will. Richard Wyman – Canaccord Adams : So to get to a couple hundred million a day net to yourself 18 months from now the services that you currently use is probably enough to get you there.

Pretty close, we may be down a frac spread, right now Apache runs a frac spread and Canada runs a frac spread and we’re just starting Apache’s pad is just coming on now so we’re just finishing the last of our fracs and that one pad is coming on so really not a whole lot more services.

Your next question comes from the line of Chris Theal – Macquarie Securities Chris Theal – Macquarie Securities: Just wondering if you can give some context to the spending plan, it is geared to a long-term view of the gas price which is substantially higher than current market. More and more what we hear is the ability to lower costs on these shale plays and more deliverability potential, so how long does EnCana stick to the investment horizon towards the long-term if we are in an environment where shale economics will drive the price for the next couple of years, when do you deviate from that long-term spending plan, or do you.

I don’t think you necessarily do. If prices stayed persistently low in the $4.00 range, and we weren’t able to satisfy our cash flow requirements over the longer term with hedging then at some point in time we would have to reduce the activity level. I think that there’s an awful lot of companies out there that will be forced to reach that decision point a lot earlier and so I do not believe in any way that the $4.00 price will stay for the longer term. Chris Theal – Macquarie Securities: And in terms of capital allocation do you see or do you have any sort of tangible movement in capital within the EnCana program right now that targets higher associated liquids plays.

Individually the teams are looking for those kind of opportunities but they have to stand up against our longer-term price [inaudible] as well.

Your next question comes from the line of Amanda Fraser – AllNovaScotia.com Amanda Fraser – AllNovaScotia.com: I was just looking for an update on the Deep Panuke project in Nova Scotia.

Not too much has changed since we talked in the last quarter, again we said that our production field center had been somewhat delayed and we’re kind of expecting it now in and around the second half of 2011. We have completed our disposal well if you will and the rig has moved on to the first of our four recompletions and things are moving along pretty good there. There’s a bit of pressure on some of the costs especially with the Canadian dollar and just some of the delays on the rigs so we do plan to update our costs and again our schedule when we’re finished our drilling program which should be over, these wells are taking us probably about 20-25 days so over the next quarter we’ll be able to update where we’re at in our costs and our timing. Other then that we did complete pipeline installation to shore so we’re in good shape there and really we’re just waiting for the production field center. The production field center when it comes in, all we really have to do, the wells will be completed at that point and we have to do just the inline gathering at that point, so really the bulk of our capital will be spent after the drilling and completion program this summer and the only remaining capital for us to spend is hooking essentially the final tie ins up in the gathering system. Amanda Fraser – AllNovaScotia.com: When can we expect first gas from Deep Panuke.

Well like I say we’re somewhere in the second half of 2011 now by the time we get the production field center over from [Abadabee] and we get it in place and we get the [gas] flowing it will somewhere in the second half of 2011. So we have had a delay in the production field center and we’re just about to lay probably in the order of about a year at Deep Panuke from our original schedule. Amanda Fraser – AllNovaScotia.com: I was wondering if, did EnCana pay a penalty or anything like that to Repsol for being late with that.

No, not that I’m aware of, we take our gas on Maritimes and Northeast and we drop it off at the Canadian/US border and Repsol takes it from there and as far as I know there are no penalty.

Your next question comes from the line of Unspecified Individual – Reuters Unspecified Individual – Reuters : I was just wondering if you could expand a bit when you said earlier you saw continued downward pressure, I’m also curious whether or not the storage situation is a concern for EnCana.

The continued downward pressure I’m not saying necessarily its going to get too much lower natural gas prices then it is right now, I’m just saying that it could be sustainable period of time and you’re exactly right because of the storage levels that we’re seeing which reflect that there’s less demand then there is production at this point in time. Now one of the things that could change that in a more positive direction is the activity in natural gas could cause the storage inventory to not rise as quickly. We’re also seeing that at this price natural gas is competing with coal for [electrical] generation in some places. That could very quickly remove the surplus. And capital availability to companies that are less financially well positioned as EnCana may be forced to reduce their drilling activity. All those things and including the biggest variable of them all which is weather. We never know how weather is going to change inventories and it can do it very quickly and very dramatically. We’re hopeful that the situation will not persist over a much longer period than the end of the year but we’re cognizant that it could stick around for a while. Unspecified Individual – Reuters : How long to prices have to be sub $4.00 before you make this shut in decision.

They don’t necessarily have to be sub $4.00, its basically more of the view of we do things on we call it an NPV, net present value, decision making so the impact, value [inaudible] but shutting in versus waiting until a higher price emerges. And there are higher prices already in the forward market if we look at next year, we’re well above 540 next year so that’s not much below what our longer term forecast is so, we have to look at it though on a field by field basis. Last year when we went through the process I think we started with 3.5 Bcfe/d of production and we ended up shutting in about 300 or 400, I guess by the end of the year it was about 500 Bcfe/d and that was where we thought in the area that it made the most sense. We’ll go through that same process again.

Your next question comes from the line of Shaun Polczer – Calgary Herald Shaun Polczer – Calgary Herald : I was just wondering if you could outline some of the impacts of Canadian dollar at par, I’m hearing a few kind of mixed messages on the call, it sounds like your American costs are lower, Canadian costs are higher, what’s the overall net impact and how does it all wash out.

Since we report in US dollars and we do our business in Canada effectively in Canadian dollars, whenever the Canadian dollar rises against the US dollar it appears like our costs are rising when in fact on a Canadian dollar basis they’re not. So its just one of those things, that becomes part of a reporting thing. Second thing that happens is some of the things we purchase are internationally priced or priced in US dollars and so with a rising Canadian dollar when you purchase things like steel, steel price then goes down, effectively is going down and any of the commodities are typically priced such as diesel are priced on a US dollar basis, so those go down when the Canadian dollar rises. Shaun Polczer – Calgary Herald : So overall is it a positive thing or a negative thing.

We have to go through that all the time and try to figure that out. In the shorter term it always appears to be a negative thing when the Canadian dollar rises. It takes a little bit longer before you’re able to get all the purchasing effects. Now some of our US denominated debt of course goes down from a Canadian dollar perspective. So there are a lot of moving parts in a company with ours which has got more than half of our assets residing in the US and most of our debt is in US dollars so I expect this answer would be very different from every company you ask. Shaun Polczer – Calgary Herald : Would there ever be any thought of switching back to Canadian dollar protocols.

Probably does not make as much sense for our company because our typical peers that we’re competing for in the financial markets are virtually all pure play US based companies and so you want to make sure that from the investors point of view, they have as much clarity between investment decisions as they can possibly get and by reporting in Canadian dollars with Canadian protocols it makes it somewhat confusing for our US investors. Shaun Polczer – Calgary Herald : When you’re ranking your shale plays like say Horn River which is in Canada and using all the Canadian costs against say the ones in Louisiana and Texas, does the FX exchange make any difference on say how those stack up against each other.

It does, in the shorter term of course it makes them less competitive. The Canadian plays become somewhat less competitive with our US plays.

Your next question comes from the line of Nathan Vanderklippe – Globe and Mail Nathan Vanderklippe – Globe and Mail : Just two quick questions on price, one just for my own clarity when you look at this five year plan what long-term price are you looking to sustain that, of gas, and second can you provide any detail on what’s supporting the higher ACO prices.

So for the longer term our price deck that we used coming into the year was between $6.00and $7.00 for a long-term NYMEX price. We’re tending to lean now towards the bottom end of that range as maybe a little bit more realistic. And then the second part of the question I’m going to turn over to Renee.

The stronger ACO prices that we’re seeing are just very similar to the stronger prices that we’re seeing all across all of the Western producing areas and its just a tightening of the differentials from ACO to [inaudible] or ACO to NYMEX and it really comes as a direct result of all of the infrastructure that’s been built up over recent years allowing gas in the west to reach the premium markets in the east and we have a surplus of infrastructure. So as long as we have a surplus infrastructure allowing that dynamic to happen we’ll see strengthening in prices in all of the western areas, including ACO.

Your final question comes from the line of Kerry Tate – National Post Kerry Tate – National Post : I’m wondering if you can explain a little bit how this cycle of inflation that you’re starting to see compares to the one maybe two years ago before the credit crisis.

I think this is largely being viewed as a recovery, an economic recovery in certain parts of the world that are driving the broader type inflation that you’re seeing. The world oil prices increasing and steel prices increasing. The dynamics in North America that are driving some of the industry specific inflation that we tend to focus more on is related to competition for pumping services. We have a lot of wells that need to be drilled and completed in shale plays in order to retain land on the natural gas side but at the same time these same services are being used to develop shale oil plays right across North America. So, that’s where we’re starting to see some tightening of services despite the fact that the natural gas commodity price is quite low. So to be different there was, last cycle everything was going up, this time its more of an industry specific one and the other things I talked about on worldwide basis. Kerry Tate – National Post : Is that to say that the inflation then isn’t as bad or as painful as you saw two years ago.

A few years we were looking at double-digit inflation rates on an annual basis. Here we’re talking about just a couple points here and a couple of points there.

There are no additional questions at this time; I would like to turn it back over to management for any additional or closing comments.

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