Good day, ladies and gentlemen and thank you for standing by. Welcome to EnCana Corporation's fourth quarter and year end 2009 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) Please be advised that this conference call cannot 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.

Thank you, operator and welcome everyone to our discussion of EnCana's fourth quarter and year-end 2009 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 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. To provide a clear understanding of the new post-split EnCana, fourth quarter and full-year 2009 financial and operating results in this conference call highlighting EnCana's results on a pro forma basis, which reflect the company as if the split transaction had been completed as of January 1st, 2008. In this pro forma presentation, the results associated with the assets and operations transferred to Synovus Energy are eliminated from our EnCana consolidated results and adjustments specific to the split transaction are removed. Financial information that reconciles EnCana's consolidated financial statement and pro forma financial statement can be found in EnCana's news release dated February 11th, 2010, available on our website. Also available on our website is our 2010 updated guidance. Randy Eresman will start off with highlights of our operating results and reserve information and then turn the call over to Sherri Brillon, EnCana's CFO and to discuss EnCana's financial performance. Following closing comments from Randy, our leadership team will then be available for questions. Before I turn the call over to Randy, I would like to ensure you're all aware of our upcoming Investor Day event scheduled for Tuesday, March 16th in Calgary and Thursday, March 18th in New York. The event will feature a series of presentations highlighting our asset base. Both days will be webcast and presentations available on our website. If you haven't already done so or received an invitation – haven't already received an invitation and would like to attend, please contact our Investor Relations team. 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. This conference call is the first time I've had a chance to speak with many of you since we completed the reorganization of the company on November 30th of last year. I'd like to thank you for your overwhelming support of the split transaction and your continued support of our strategy. I'm very pleased now to talk with you today about our peer play natural gas company. We believe new EnCana has positioned extremely well operationally and financially to choose strong future growth. First, I'd like to highlight our performance in 2009, a year of challenges and a year of change. And also a very successful year for EnCana and a year that I believe underscores the strength and sustainability of our business model and the capability of our teams to respond to the changing environment and changing operational priorities. The biggest issue that impacted the entire natural gas industry was the lowest average commodity price in seven years. However, our long-standing approach to risk management served us well, stabilizing our financial performance for the year. In addition, we responded prudently by shutting in or curtailing some of our productions to the lowest point in the price cycle helping to preserve value for our shareholders Another change unique to our company was, of course, the reorganization of EnCana. Through this busy and demanding process, EnCana employees worked very diligently to make the transaction as smooth as possible and I would like to thank them for their great efforts. Despite the potential distraction and transformation of this magnitude may create, our teams stayed focused on managing their respected businesses in delivering strong operational and financial results. Across our portfolio, we continue to see superior operational performance from our key resource…

Thanks, Randy. As Randy pointed out, despite a challenging economic environment, EnCana continued to demonstrate capital discipline and financial strength. This is reflected in both our year end results and our current financial positions. 2009 cash flow was strong and exceeded our guidance expectations. Supported by our commodity price hedging program, EnCana achieved pro forma cash flow of about $5 billion or $6.68 on a per share diluted basis. Realized after-tax hedging gains of approximately $2.3 billion or about $3.15 per thousand cubic feet equivalent, provided stability to our cash flow through the year. Our pro forma cash flow of $5 billion is aligned with our November 12, 2009 guidance of $4.2 billion. Once the tax associated with the windup of our Canadian oil and gas partnership and transaction costs are adjust, for as previously noted in our guidance. Our strong cash flow performance was accompanied by strong pro forma operating earnings of approximately $1.8 billion, or $2.35 per share on a diluted basis. These earnings figures were again, supported by our risk management program. Looking forward, as of January 31, 2010, we have approximately 60% or about 2 billion cubic feet per day of our expected 2010 natural gas production hedged, for the calendar year, with fixed price instruments at an average of $6.4 per thousand cubic feet. In addition, we currently have fixed price swaps on about 935 billion cubic feet per day, for 2011 and about 870 million cubic feet per day for 2012, both at an average price of about 650. As we witnessed in 2009, having hedges in place help provide protection on the downside, creating increased certainty for our cash flow, capital program and dividend. Our hedging arrangements are with a diversified group of approximately 20 different counter parties with strong investment grade credit…

Thank you, Sherry. EnCana continues to demonstrate what we believe to be industry leading performance from the developments of unconventional natural gas resource plays. Our portfolio was strong in assets, supported but solid financials is a direct result of our focused strategy. We've been building our North American portfolio, fine-tuning our approach to resource developments and establishing strength and flexibility in our balance sheet for years and that discipline is paying off now more than ever. Overall our 2009 results are very positive and indicative of the strength of our company. Like any year, 2009 had its challenges and its triumphs. But our strategy appearing low-risk, low-cost North American resource plays with a strong balance sheet and favorable commodity price hedges, has allowed us to be resilient to the lowest part of the commodity price cycle and maintain our position of strength. As we move forward in 2010 and beyond, we believe that North American natural gas prices will be, on average, lower than what we've seen historically. Our operating practices, leading technologies and increased efficiencies position us very well to continue to capture strong margins and strive in a competitive price environment. Sherri pointed out earlier we have a strong balance sheet and are extremely well positioned to financially to capitalize on potential investment opportunities that may arise. Risk management program aims to underpin our capital and operating programs and we are maintaining our focus on applying advanced technology to increased operational efficiencies across the company. Our 2009 performance demonstrated that even through a significant economic downturn, our ability to create shareholder value was sustained. We're well positioned for the future with an asset base capable of delivering double-digit growth for the long-term, while at the same time working to further reduce our cost structures and improve operating efficiencies.…

(Operator instructions) Your first question comes from the line of Greg Pardy from RBC Capital Markets. Your line is open. Greg Pardy – RBC Capital Markets: Thanks. Good afternoon. Randy, you're sending some loud messages. I mean, certainly in terms of gassage is owed in 2012 and you've alluded to it, but what is your thought process there and why you hedge out this far if there is the potential for just a recovery on the industrial demand side?

Thanks, Greg for the question. We do an evaluation of North America's natural gas supply and on the conclusion of that analysis we believe that there is considerable amount of domestic gas plays, particularly in the shale plays, but also other plays that benefit from the technology. Greg Pardy – RBC Capital Markets: Randy, you're a little hard to hear.

You know what? I didn't have my Mike on. I apologize for that. Greg Pardy – RBC Capital Markets: No problem.

What I was saying is that – EnCana does and has for a number of years done a fairly exhausted evaluations of the fundamentals of North American natural gas supply and it's our view that the efficiencies created by horizontal drilling and mass hydraulic fracturing stimulations of wells and shale plays and others that benefit from that technology, that we are seeing that the supply can meet demand at a much lower price than historical and I guess our view is that natural gas price is at a lower level in and historical expectations are here to stay. And so the companies that can do best in that environment are the ones that can operate in plays and create the – and have the lowest overall supply cost and we believe that, despite the fact that we expect natural gas prices will not likely rise to historic levels, we will still be able to develop very good margins in that environment. Greg Pardy – RBC Capital Markets: Are you changing your mid-cycle pricing expectations?

With every new piece of information we receive, we're more confident and the ability to continually lower supply costs. The only – the wildcard in all of this, this inflation at some point kick in. So, when I reference the lower supply cost, I'm really talking about in reference to today's cost structures. But efficiencies are continually improving in all of our plays, to the extent we could have never imagined a few years ago. Greg Pardy – RBC Capital Markets: And just point of reference, 650 was your last, is the price you run with now, correct?

That was our most recent price tag, yeah. We ran 550 for 2010 and 650 beyond. So we're seeing some amount come off of that. I don't think we are going to be specific about it, but we are seeing it come down a bit. Greg Pardy – RBC Capital Markets: Okay. And last one for me is more fully loaded F&D number that would include undeveloped land and gathering systems and so forth. That number may have been the release, but could you just mention what that would be as opposed to the $1.62 you quoted?

Bob. Do you have that number handy? I think it's around $1.80.

A $1.98.

A $1.98. Greg Pardy – RBC Capital Markets: Okay. Thanks very much.

You're welcome.

Your next question comes from the line of Chris Theal with Macquarie Securities. Your line is open. Chris Theal – Macquarie Securities: Good morning. Can you hear me, okay?

Really good, Chris. Chris Theal – Macquarie Securities: Okay. Just a question, Randy. With respect to new plays, can you comment, what's sort of common horizon with EnCana? Both in the U.S. and in Canada and I'm curious if you guys are looking at the Devonian Shale number and they have been planning in land sales at all there?

Okay. I'm not sure we are going to divulge too much on plays. We haven't talked about in the future at this point in time, but I think we can talk about exciting things that are happening on plays, you're probably aware of. I'll let Mike talk first about Canadian plays and then Jeff will maybe talk a little bit, what we're doing in the U.S. Chris Theal – Macquarie Securities: Thanks.

Hi, Chris. Mike Graham here; I am with the Canadian division. Talking about the Devonian Shale number, we do think that the Devonian Shale can emerge as a big player numbered and you've recently seen on the land sale activity. So, I think it's sort of a vote of confidence for what Alberta is doing in their competitiveness review. And we do attend a lot of land sales in DC and Alberta as well. So stay tuned for that. Just a little bit maybe in the Horn River, Chris, what we have. The horn river, like Randy said, we continue to drill our wells a bit longer. We're getting out to 2,200 meters now in the horizontal. We're putting in more wells per pad, as many as 16 wells per pad and we're actually putting more fracs per well. The teams are looking at putting 22 fracs per well and about 200 tons per frac. And like Randy said, the results from our ten and 12 frac and 14 frac horizontals have been good, averaging 8 to 10 million cubic feet a day for the first month and we do think that our wells – with 22 fracs per well are going to be that much better again. So, we only put on four wells for 2009 and we are doing these as a pad, if you will, so we're going to have a lot of production coming on for 2010. We're going to exit 2010, we think about a 100 million cubic feet a day net to EnCana with a couple of paths coming on through the year and, 2011, we think we'll exit at about 200 cubic million feet a day that to EnCana. So like Randy alluded to, we drilled the longer, put in more fracs and…

Thanks, Mike. And I'm going to talk about the Haynesville a little bit. And, Chris, when we talk about our land retention strategy in Haynesville, we talk about drilling 50 wells in 2009. An additional hundred net wells in 2010 and then finishing off that program in 2011 with an additional hundred wells, which by and large attacks about 165,000 net acres of our land position. Of course, our land position is 430,000 net acres. So we're really talking about attacking the areas where we have originally acquired our land in what we think is the core of the Haynesville trend and we're rally attacking just that area. There's another area so called phase III area within the company that we'll be looking at in the 2010 and 2011 area that's another hundred thousand acres. So now just within that 165,000 acre area that we're currently planning and working on the expiring component of our land base, there's a tremendous amount of opportunity. In this current quarter, we announced a well that we've drilled in the mid Borger. We haven't focused a lot as an industry and a company on the mid Borger potential. But the impact to EnCana's resource potential is very significant. Obviously, you've heard a lot about the Haynesville by itself is producing over 2 BCF a day. Canada for its part is currently producing 200 million cubic feet a day just from the Haynesville and just on wells that we're drilling on a per section basis. Nonetheless, they are still growing. The mid Borger has the capability of rivaling our Haynesville position in the play and certainly the results that we are getting, the more customarized completion programs associated with mid Borger are giving us new well results that are – that rival the Haynesville itself. So just in that sense we can – we can have thousands of wells that we potentially could drill in that 165,000 acres. Beyond that, we can continue to work on 430,000 acres. So I hope that gives you a flavor of the immense potential that we have. Chris Theal – Macquarie Securities: Jeff, how many horizontals are in the mid Borger now?

In the play? Chris Theal – Macquarie Securities: Yeah.

In the mid Borger? Chris Theal – Macquarie Securities: Yes.

We have three or four ourselves. I would say, as an industry, we have dozens but not many. Now, we also have a couple thousand industry verticals as well, that have targeted and test results. So it's really in its infancy compared to Haynesville. There's a number of reasons. First of all, the mid Borger potential seems to be more in a southern and central component of the play extent. It's not as prevalent or as prospective I should say. You know, a lot of the northern areas which have been developed earlier in the play history. But the mid Borger really has strong reservoir capability in the area where EnCana has its land base. And we haven't really gone after it so to speak because of the land retention; we need to drill through the deepest zone, which is the Haynesville and producing quantities. So it kind of goes a little bit against our land retention strategy to drill mid Borger. That doesn't mean we don't like it though and it doesn't mean that it doesn’t have the capabilities to drive in Haynesville, ultimately in our quarter end. Chris Theal – Macquarie Securities: Thanks for those answers guys. But one more thing, if I can bug [ph] can you just walk through your additions by resource play one more time?

Addition by resource play? Chris Theal – Macquarie Securities: Yeah.

Okay. For a second, all right. So we have booked about 600 BCF in Hendril [ph] Jonah we added another 400 BCF that was a largely due to down spacing to (inaudible) take a spacing to some parts to play, Cutbank Ridge, commodity that’s added 285 BCF. Greater Sierra area I guess 195 BCF and Bighorn depressant price 175 BCF and then now is offset by the CBM write-down nice spoke. Chris Theal – Macquarie Securities: Thanks very much.

You're welcome. Thank you.

Your next question comes from the line of Brian Singer with Goldman Sachs. Your line is open. Brian Singer – Goldman Sachs: Thanks. Good morning.

Good morning, Brian. Brian Singer – Goldman Sachs: Following up on your comments on the mid Borger when you think about capital to commit, how many wells do you expect to grow on the mid Borger and of your acreage position in net? What do you think you will and that’s going to keeping over the next two years and what do you think you lend up is surrendering any?

Jeff, go ahead.

Good morning, Brian. With a big Borger, we probably want to drill, less than 10, 100 wells in our program for this year, specifically the mid Borger. Again, we want to – keep 165,000 net acre strategy in land attention in place. The answer to your question Brian is really a schedule advance in the next 2008, I'm sorry, 2009, 2010, 2011 period we really have expiries reason associated with the 165,000 net acre position, so go page three are you going to mentioned earlier of the 100,000 acres begin to expire 2011 but the leases and the terms of leases are more favorable for retention. So we can do continues drilling operations that we choose but we are also can group leases together greater 640 acre basis. So I think as we go down to time we are going to look at the information either from the industry hopefully the industry will prove up reminder of our land. And we are also looking at our own drilling results development strategy on potentially saving all over land. We haven’t condemned any of our 435,000 acres as being not commercial. We feel ultimately that we have straitening and that’s going to five year so now but before we kind of get there. Brian Singer – Goldman Sachs: Thanks. And Randy can you give us, you saw to latest thoughts on Marcellus and whether you see EnCana taking a greater role?

With regard to Marcellus, we did do the small entry position and what we would like to do right now as make sure we understand the issues and I guess the profitability of the pipe report we decide whether not there is something in area that we could plan. But I guess the real answer is we weren’t there first and we would like to be person in that place and so we think they are maybe other opportunities where we can find just as good plays but from an exploratory stage. Brian Singer – Goldman Sachs: Thanks. I can ask a one last little follow-up. You mentioned 8 to 10 million cubic feet per day, IPs and Horn River Basin and what your expectation for UR associated with those well?

Yeah, Brian. Mike Graham here. We’d like to say it's very early in the Horn River, Haynesville, a lot of this emerging type share price but these are very encouraged. We think we may get as much as much as 0.8, even in the much 1 Bcf for frac on an yearly basis. So we may have well but that would be 10 to 15 Bcf see largely in the Horn River. I would like to say its early we don’t have log on for couple of years but that the clients terms are according to (inaudible) Brian Singer – Goldman Sachs: Thank you.

Your next question comes from the line of Mark Gilman with Benchmark. Your line is open. Mark Gilman – Benchmark: Guys, good morning. I wanted if you could both Jeff and Mike talk a little bit about the production numbers, both in the deep Borger, East Texas in the fourth quarter as well as Mike, I think, the Cutbank in the fourth quarter but volumes in both were really low and I was hoping you could relate that to Randy’s comment as to the areas of the Shut-ins and what particular place, where was production being most significantly impacted by the Shut-in. Also a comment as to whether the 125 the day indicated number as we speak includes or does not include differed completions and where we stand on that one? Thank guys.

Hey, Mark. Mike and Jeff just refreshing results of the numbers but the areas that you spoke of are the areas that we did target the Shut-in gas and most of that gas as we said was – we started to bring it back on screen as went ahead, price started to rise again. Mark Gilman – Benchmark: Mike, how much gas did you slot Shut-in, I think, you said it was around 125 at the end of January but we started bringing back?

Yeah. Well, we probably have about of that still shut-in really somewhere in that order. We think sort by the end of this month, we will have most of that back on target. But we did have, we head for trip contained a lot of volume. We drill a lot of well. We decided not to complete them so we are out there completing in off a lot of well in Cutbank as well and before never like to say we only put on four well in the board member last year. We drill like 20 net well in the Horn and we drilled another 20 net well. So we’re starting bring this big well pattern. We started very low production a day probably less than 20 million cubic feet a day, that kind of Horn River and I get to say we should access about 100 million cubic feet a day in the Horn River and for Cutbank Ridge and sort of a Q4. We did have some problems, we may have heard about that we have a gas leak up and round Dawson Creek and we decided to shut in and to some 190 well. So we actually took about 250 million cubic feet a day offline and then Q4 plus that curtailment if you will and like Randy said at the end of January had about 125 million cubic feet a day Shut-in. So we will bring that Shut-in volume back on over the next month and we are out there now and to a lot more completions that we did in 2009. So volume for a Canadian division will continue to ramp- up. We actually were very close to our budget in January which we’re excited to see and we are going to have good growth throughout the year. So we are very confident in our approach. Mark Gilman – Benchmark: Okay.

Yeah. Good morning. Mark. In U.S. Division, our annual production for last year was just over 1 point Bcf a day and we have stated that we had about 200 million a day annualized Shut-in during the year. East Texas was one of those areas that we probably are in place. Current production is around 1.9 Bcf a day meaning that we are going to step it up and brought on most of our additions. So I am quite pleased on how the gas has been able to come back on right where we want to be, the specifics around East Texas, East Texas was where we chose to Shut-in our production. We have full year average production of 324 million and as we speak right now, our produces been over 450 million. So it gives you kind of flavor of how much we shut-in and how will bring it back? In the majority of the U.S., the division has all of its gas on?

Mark, I should also add that in before the quarter, we would have seen the sale of our (inaudible) asset show up as a reduction of about 60 million a day but we are also part of the impact on the quarter. I wonder well, I had – I am a little bit surprised Randy given what you and your colleagues have said about your supply cost and may be Jeff can comment on this? About the size of the price related revision, the 9/14 number in the U.S. division, may be, give me a little bit of color Jeff on why that number is quite so large on the basis of – we have price on the 380 range.

380 is a pretty low price. Mark Gilman – Benchmark: Yeah.

380 is not our expected business case. Randy talked about some of the pricing for but. It reflects some of the higher cost structures that we have in the Rockies versus the Piceance basin. But again, we don’t think 380 is really what we should measure our business case or expected values from and so that is why we have given you our best case. Mark Gilman – Benchmark: Jeff, are these price related revisions? That 9/14 in the U.S. is that all the products?

Yes. Yeah. The short answer is yes. Mark Gilman – Benchmark: Yeah.

We have been present in Canada as well. Mark Gilman – Benchmark: Okay, guys. Thanks very much. I appreciate it.

Thank you.

Our next question comes from the line of Bob Morris with Citigroup. Your line is open. Bob Morris – Citigroup: Thank you. Good afternoon. Following up on the reserve question, you noted here that pro forma percentage was 44% at the year in ‘09. I didn’t see a figure in there as to what that percentage cost pro forma at the end of ’08? Do you have that number?

Yeah. Just a second.

Yeah. That number was just above event. The number was 41% at the end of 2008 pro forma. Bob Morris – Citigroup: Okay. Thank you. Second question, quick here. It looks like that apart from shut-in gas production was up at the end of January about $125 million a day, what I have averaged in the fourth quarter? Was that increase mostly in Haynesville. In other words, the increase separating at shut-in has come back on line. The increase in production at the end of January versus fourth quarter average.

Go ahead, Jeff.

Bob – Jeff Wojahn speaking. I think it’s more of a function of the flush production associated with bringing on the new production. Obviously, at Haynesville results are adding to that. It sounds about it was included in their budget as well. Bob Morris – Citigroup: Okay. And then, last question, you mentioned that you’ve moved down your mid-cycle prices $6.50 and then now previously you mentioned that the chronicles is only economic above $6.50. What is that purchase in regard to that project now?

On a go-forward basis, the project is almost belted; it will be done by the end of this year. The economics are pretty good going forward and that’s really going, we have to think about it. Bob Morris – Citigroup: Basically, on an incremental basis going forward with a prior cost just on …

On a full cycle basis, it’s pretty breakeven, I think. Bob Morris – Citigroup: Okay. All right. Good. Thank you.

The next question comes from the line of Ray Deacon with Pritchard Capital. Your line is open. Ray Deacon – Pritchard Capital: Yeah. Hi. I had a question mark regarding the number of frac stages on the middle Borger well that you put on and also in the your wells that averaged 20 million a day for an IP [ph] origin in Haynesville. How man frac stages are you doing on those?

Sure. Jeff will answer that. Ray Deacon – Pritchard Capital: Thanks.

Good morning. Generally, we’re trying to drill as long as horizons began and stay within our six hori space and which means that by large during that foot range for horizontals and even most recently gravitated towards 14 stages about former line parallels per well for both the mid Borger and the Haynesville. Ray Deacon – Pritchard Capital: Got it. Right. And also I just want to take a picture of question. When you show the slide of all the major producers and where are you rank there. It seems like a lot of those companies are now trying to grow production more aggressively than they have in the past and if you, kind of, listen to EOG yesterday, they still felt this though you’d see a maybe a two to four BCF decline in production versus thick level seen last year, I guess. What are you thinking at this point?

So you may be talking about in terms of market demand, North American demand. Well, so I mean, on the other side, in terms of supply, I guess, what would be your thought on 2010 versus 2009. I think, it will probably be very matched to the demand side. So I don’t think we are going to go much. Ray Deacon – Pritchard Capital: Right. Okay. Got it. Do you have any kind of view on the headcount that would be required to maintain flat production, I guess.

We can give a pretty put some presentation at our Investor Day on March 16 in (inaudible) and 18th on New York. I think a lot of these more details are answers. We will be providing investors and analyst with tremendous amount of information at that time. Ray Deacon – Pritchard Capital: All right. Thanks very much.

Your next question comes – we are now taking questions from the media. Your next question comes from the line of Amanda Fraser with AllNovaScotia.com. Your line is open. Amanda Fraser – AllNovaScotia.com: Hi. I was just wondering what the impact of the midway in drilling will have on first half?

Mike Graham will answer that.

Hi, Amanda. Mike Graham here. We were scheduled to bring different owner Sanchez [ph] in Q4 2010. The product feels senate and they will be dealt in Abu Dhabi and its getting out of Abu Dhabi, a little later or so. We actually slipped probably in Q1 2011 or Q2 2011 somewhere in that order. The delay of the rig getting out of the harbor as we had to wait for the right things to get the rigor on site. You know, Ray will set us back at where it is, more so on the production center. We were all in, we have drilled the first level of that program where we have reached TD on a disposal level and everything looks encouraging there and we are going to move on to a slowly completion after that. Amanda Fraser – AllNovaScotia.com: Working over, in fact, on the project, is that, TFC being late.

Well, you know the project is just a later quarter two side thing on that. So we still expected to come on, add about 200 million cubic feet a day and that we’re just acting accordingly and that’s really just a small delay in the project. Amanda Fraser – AllNovaScotia.com: Okay. And what about in terms of the capital cost, it would have occurred with different estimate there?

There has been – there has been a big creep on the capital. Obviously delay from the rig and now from the harbor were still going to pay a day rate of the rig sip there, a standby rate if you will. So we do have a little bit pressure on the cost. Eventually when we sanctioned the project, it was about $760 million Canadian. We think we’re probably at about $800 million range is hopefully where the project is going to end up. There has been a little bit of pressure as well as you know the strong Canadian dollar as well. Amanda Fraser – AllNovaScotia.com: And I just have one last question, just given the current gas prices with us, the project have been approved back in 2007.

Well, I think Randy will answer that one.

I would say that there is more caps. Amanda Fraser – AllNovaScotia.com: Montney first.

It is in Montney [ph]. Amanda Fraser – AllNovaScotia.com: Could you just say that asset, could your raise your voice, could you just touch on that?

Hello. Sorry. I have a problem turning that mic on this morning. If the curve prices are – curve prices outlook had existed back in 2007; this project would have been more challenged there than approved. Amanda Fraser – AllNovaScotia.com: Okay. Well. Thank you.

Your next question comes from the line of Dina O'Meara with Calgary Herald. Your line is open. Dina O'Meara – Calgary Herald: Thank you. Just two questions, one do you expect Horn River to become commercial?

Mike. Dina O'Meara – Calgary Herald: First question.

Yeah, Dina. Mike Graham here. Like you say, we’re going to commercial development right now, if you will. We’re going to be producing – we’ll be average about 50 million cubic feet a day for 2010 and we should access 2011 at about 200 million cubic feet a day that to EnCana. So it is definitely commercial and all systems go on a Horn River. We have about 2.5 net really working there now and we drill as I say, may be 16 to about 20 wells per frac. Our drilling rig may be out there but as long as close to the year drilling one of these well pads and then we got to have to go in factures, stimulate that, that well pad which may take as, as much as six month if you were fracing around the clock, 24/7 now. And we do about two to two and half fracs each and every day. So this is probably close to the true gas manufacturing project as you can get. Dina O'Meara – Calgary Herald: Do you have pipeline capacity to take it out to a plan?

Yeah. Right now, there is about 500 million cubic feet a day of excess capacity in the Fort Nelson, sectors Fort Nelson plan. So, we do plan to fill that up over the next few years and then by 2012, mid of 2012 – is where we would be in the 400 million cubic feet a day plan that EnCana is building, it will be on and then that's 200 million cubic feet a day will flow into TransCanada's Western mainline. Dina O'Meara – Calgary Herald: Okay. What about pipeline? Getting the gas out of the Horn River?

Well. I can say we will bring in that initial 500 million cubic feet a day, ourselves and the Horn River producers. We will pipeline in it to sector for Nelson Gas, right into Spectra. Our well setup there, there is a lot of type in the area. Dina O'Meara – Calgary Herald: Okay. Because I understand TransCanada had to lead the in service date of its Horn River mainline because of concerns by Horn River producers on commerciality to delay later the year.

Yeah. That's right. We have delayed. And like I say we are still planning on being up sort of mid-year 2012, may be September, 2012 at the latest. Dina O'Meara – Calgary Herald: Wonderful. My next question has to do with Randy comments on – could you expand a little bit on land capturing new play in Western Canada that you mentioned?

Look we have spend some additional money in Canada and in several of our U.S. areas, looking for new perspective shale gas place and until we are ready to speak to about the specifics of them, we just need to keep to confidential usually when you are in land capture mode, when opportunities arise, it's not a wise thing to be making a lot of announcements. Dina O’Meara – Calgary Herald: Well. Obviously everybody’s interest was piqued, when you spoke about a new play in Western Canada.

And it should be. Dina O’Meara – Calgary Herald: Thank you so much. That's it from me

You’re welcome.

There are no further questions at this time. I will now turn the call back to Mr. Eresman. Please go ahead, sir.

Well. Thank you everyone for joining us today to review EnCana’s fourth quarter and year end results. Our conference call is now complete.

Thank you everyone for joining us today to review EnCana’s fourth quarter and year end 2009 results. Our conference call is now complete.