Good day, ladies and gentlemen, and thank you for standing by. Welcome to EnCana Corporation's Fourth Quarter and Year-End 2010 Results Conference Call. [Operator Instructions] 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. Welcome everyone, and thank you for joining us today. 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 U.S. dollars, and production volumes are reported on an after-royalties basis. References to reserves, or resources information will be on an after-royalties basis, employing forecast prices and costs unless otherwise noted. To provide a clear understanding of the 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 2009 results associated with the assets and operations transferred to Cenovus Energy are eliminated from EnCana's consolidated results and adjustments specific to the split transaction have been removed. EnCana's fourth quarter consolidated financial statements and supplemental information with 2009 pro forma comparatives are available on our website. Randy Eresman will start off with the highlights of the Co-operation Agreement we've reached with PetroChina, as well as an overview of our 2010 operating results and 2011 budget. Jeff Wojahn, Executive Vice President and President of our U.S.A. division; and Mike Graham, Executive Vice President and President of our Canadian division, will then touch on some highlights from each of their areas before turning 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. I'm very excited to speak to you about the Co-operation Agreement we've reached with PetroChina, as well as our 2010 results and our 2011 capital program. The agreement we announced yesterday with PetroChina represents a major step forward in our plans to unlock the value contained in our enormous portfolio of natural gas resource plays and to double EnCana's production per share over the next five years. For the last number of years, the North American natural gas industry has undergone significant and permanent change. Technological advancements and operating practice innovations have changed the game, rapidly transforming supply sources that were once thought to be a high cost to some of the most prolific mid- to low-cost basins in North America. EnCana has been at the forefront of this transformation, leading to innovation and cost reduction. We've assembled some of the best natural gas resource plays in North America by focusing on high-quality resources, creating technological advancements and applying innovative operating practices to help develop these plays to some of the lowest cost in the industry. However, the value of our company and the effect the value of natural gas resource plays relative to historical views on conventional asset bases is something we believe the market has under-appreciated. As a result of the significant increases we've achieved in the size and the quality of our asset base, it has become clear to us that the greatest value proposition for our shareholders is to bring forward the value of certain of these assets by developing them at a sustainably higher growth rate. Last March, at our 2010 Investor Day, I told you about our plans to double EnCana's production per share over the coming five years. An integral component in…

Thanks, Randy, and good morning. 2010 marked another solid year for the U.S.A division, with production volumes averaging just over 1.9 billion cubic feet equivalent per day, up nearly 14% over 2009 volumes. This growth was achieved despite the impact of divestitures, which resulted in a year-over-year decrease of approximately 65 million cubic feet equivalent per day on an annualized basis. Our year-over-year growth is partly due to bringing our 2009 capacity reductions back online at the beginning of the year, and is partly driven by strong results across our division, particularly our operations in the Haynesville shale and in the Piceance Basin. The U.S.A division's 2010 operating costs of $0.56 per thousand cubic feet equivalent are more than 10% below our original March 2010 guidance. A credit to our teams and their ability to continue implementing operating efficiencies across our business. This reduction in operating costs was achieved despite average cost inflation of about 9% in the U.S.A division last year. Cost pressure has been greatest on pumping services where last year we saw average cost increases of 10% to 40%, depending on the basin or area we operated. This combined with declining natural gas prices, led us to the decision mid-year to pull back our spending and release some of our higher-priced equipment. We began to look for innovative ways to manage our completion costs and realized that we needed to change our relationship with our vendors from short-term service agreements to long-term strategic partnerships. By developing unique, long-term low risk collaborative solutions with our vendors, we believe we can play a larger part in managing the distribution of services, and as a result, achieve significant efficiencies in the field and maximize our realized margins. We now have long-term contracts in place with three service companies who will…

Thanks, Jeff, and good morning, everyone. We've achieved tremendous results in the Canadian division in 2010, with total annual production averaging about 1.4 billion cubic feet equivalent per day, up 6% from 2009. This year-over-year growth was achieved despite the impact of net divestitures, which resulted in a decrease of approximately 65 million cubic feet equivalent per day on an annualized basis. Our production growth was partly a result of bringing our 2009 capacity reductions back online, but mainly due to successful drilling programs. 2010 operating costs came in about 4% below guidance expectations at $1.06 per thousand cubic feet equivalent, which were more than 10% lower than our original March 2010 guidance. Excluding the impact of foreign exchange, operating costs were $0.96 per thousand cubic feet equivalent in 2010 or approximately 12% lower than 2009. Lower per unit costs are attributable to production growth and improved operating efficiencies across all our resource plays. The most notable production increase in 2010 came from our Deep Basin business unit where our Bighorn and Cutbank Ridge key resource plays delivered average annual production growth rate of 37% and 28%, respectively. At Bighorn, 2010 production volumes averaged 239 million cubic feet equivalent per day as we continued to see impressive results from our Falher horizontal drilling program. To date, eight Falher horizontal wells have been drilled and completed in Kakwa, seven of which are on production. The wells were completed with an average of 13 frac stages, and initial flow rates have averaged 9 million cubic feet equivalent per day. These seven wells have significantly exceeded expectations. Additionally, during the fourth quarter, we drilled and completed our first horizontal well in the well rich formation at Redrock. The well has flowed at a restricted rate of 9.5 million cubic feet equivalent per day…

Thanks, Mike, and good morning. Well, Randy covered most of the details of the Co-operation Agreement with PetroChina. I'll address our thoughts on the use of proceeds. With the transaction anticipated proceeds, we will continue to pursue a balanced approach to disciplined capital investments, maintaining financial flexibility and liquidity and strong investment grade rating, while providing strong returns to shareholders through dividends and share purchases under our normal course issuer bid. As always, we will continue to manage our capital programs and balance sheet in a highly disciplined manner. To be clear, the 2011 capital program we announced today was planned with a direct line of sight to the potential foreign agreement with PetroChina. We will not pursue growth at any cost, but this transaction will enhance our ability to take a longer-term investment view as we pursue the development of our assets. Let's turn now to our 2010 performance. Despite the challenging economic environment, we achieved solid financial results in 2010. Proof of our continued focus on risk management, capital discipline and our company-wide efforts to lower costs and maximize margins. In 2010, EnCana achieved cash flow of $4.4 billion or $6 per share on a diluted basis, which represents a 10% decrease on a per share basis year-over-year. This was accompanied by operating earnings of $0.90 per share on a diluted basis compared to 2009 operating earnings of $2.35 per share diluted. The lower comparative results in both cash flow and operating earnings generally reflect a combination of lower realized financial hedging gain, higher transportation expense and higher interest expense. Additionally, higher depreciation, depletion and amortization impacted operating earnings. These factors were partially offset by higher production volumes and higher realized commodity prices before hedging. Net earnings in 2010 were about $1.5 billion or $2.03 per share diluted,…

Well, thank you, Sherri. As you've just heard, despite the low natural gas prices that continued throughout the year, 2010 was another year of strong operational and financial execution for EnCana. And with the announcement of our Co-operation Agreement with PetroChina, I feel confident that despite the persistence of lower gas prices, we will make significant strides in 2011 towards advancing our goals of increasing our productive capacity and gaining recognition of the underlying value of our assets. As we further refine our 2011 plans, we will continue to adhere to the underlying strategic principles that have been integral to our company's evolution and success so far. We'll focus on what we are best at, the identification and development of resource plays and a disciplined capital and project execution. We continue to high-grade the portfolio and maintain financial and operational flexibility while delivering on our commitments. Since the redefinition of EnCana at the end of 2009, we continue to demonstrate our ability to deliver solid cash flow and earnings, pay a stable dividend and reduce costs and continue to invest in the underlying productive capacity of our huge resource portfolio for future years' growth. And we have indeed been able to do this in a period of low natural gas prices. Our 2011 capital program appropriately balances our priorities to grow production over the long term and advance strategic priorities on managing the realities of current commodity prices and continued focus on reducing costs. I'd like to take this opportunity to welcome Mike McAllister to our Executive team. Mike currently leads our Canadian Deep Basin business unit, and was instrumental in achieving the Co-operation Agreement we've achieved with Petrochina. Mike's involvement at the executive level will provide strong leadership and oversight of this joint venture. Thank you very much for joining us today. Our team is now standing by to take your questions.

[Operator Instructions] Your first question comes from the line of Andrew Fairbanks with Bank of America.

I had a question for Jeff, if I could. I wanted to see if you could add some details to your plans for the Haynesville in 2011? And secondly, there seems to be a bit of controversy out there on what the Haynesville returns actually are like. I wanted to give you an opportunity to say how you see the returns on your lands versus the rest of the portfolio, if you could.

Andrew, Jeff Wojahn here. Plans for the Haynesville for the upcoming year will be to transition from primarily a land retention strategy to primarily what we call a gas factory, or multi-well pad drilling scenario. And I think, when you talk about the economics and what the industry has gone through, we have gone from delineating the entire basin, so to speak, through land retention drilling. And certainly EnCana and our partner, Shell, have undertaken it for fairly significant effort over the last 30 months to go through that exercise. And what we've learned is, obviously, that there are fair quality reservoir areas and more challenging reservoir areas. And when I speak of more challenging reservoir areas, in general, clay content and more material for a geological point of view, of the Haynesville increases to the north and into the West. And in those areas, we've had dispositions this year, and also as you move east and more deep into the basin, we tend to be challenged by high pressure, high temperatures, which the industry is working on from a technology point of view, as well as faulting and structure. And into that end, we've been able to evaluate some of our lands, and we revised, we've allowed 12,500 acres to expire in some of those challenging environments. So that's kind of the exercise we've gone through and I think when we look at it today, we think we have a very comprehensive understanding of the priority of drilling opportunities moving forward. And we feel that those activities are leading opportunities within our portfolio, certainly in the tri-gas component of our portfolio. Obviously, it plays at our liquid advantage today, tend to be the cream of our crop from a portfolio point of view. Earlier, certainly internally in the company, we talked about our ability to achieve a $4 supply cost throughout our operations with the long-term target of achieving $3 supply costs. And I see no reason that the Haynesville cannot be leading the company or being part of the company's desire to move to more than $3 supply costs as we move to gas factory drilling and more efficient operations than we have today.

Would you see long-term production still reaching or exceeding the one Bcf a day level?

Absolutely. When we look at the resource potential of our land and the reserve recognition that we've been able to achieve through the land retention drilling, we see the Haynesville being a very strong contributor to not only the U.S. division's growth, but also the corporation from a long-term perspective.

Your next question comes from the line of Greg Pardy with RBC Capital Markets.

So just maybe a couple of MIDI questions up front. With the proceeds of $5.4 billion, will there be any tax impact, or is that a clean number in terms of the proceeds that will accrue to you?

Greg, there will be some tax implications resulting from the sale of the shares of the subsidiary, likely to be a capital gain type transaction. Sherri Brillon can expand on this.

Yes, Greg. This will be a structured transaction. So under the Co-operation Agreement, it's currently contemplated that EnCana's going to sell to PetroChina all of the shares of a wholly-owned operating sub that holds 50% interest in the Cutbank Ridge business asset. And so what we're expecting is that the tax on the capital gains. We'll make every effort to try to minimize that from the disposition of shares by using our existing capital losses.

Is it a material number, do you think at this -- I mean, you've obviously looked at it, I'm sure of it.

Is it a material number? Well, I think once you do the math on the capital gain, you'll see that the number looks reasonable in light of the size of transaction.

I guess the other big question is just timing in terms of cash flows and so on. And I understand that PetroChina then has the option for a fixed, a lump sum payment or payments over time. Obviously , that's going to impact the potential for you to flow some of the proceeds into a share buyback. Just wanted to understand on what you're thinking, or is it still a little bit too soon, given that the transaction really hasn't been consummated?

I'd say that is the case right now. We would prefer to be much more clear on the details of use of proceeds following the close of the transaction. And we're fully expecting that the transaction will close by about mid-year. The biggest hurdles to overcome are the Canadian, and from a time perspective, it's the Canadian and Chinese regulatory approvals.

But Randy, no change of philosophy, though, insofar as maintaining per unit growth? I mean, you've done that in the past where you've put money into share buybacks or in the dispositions, No change there from this perspective, right, on this deal?

Yes, I would expect you would see a consistency in behavior.

The other question I wanted to ask you is just around the Montney. So obviously you've sold the lion's share of the production. But there's still a significant resource. What does that profile look like when you actually get down to business? Like just from a production standpoint, would you expect to replace that $250 million a day within three or four years? I just want to get an understanding there.

We have developed some plans, but we're not really ready to fully disclose them. But what we can say is that we will increase our pace of developments at a rate which is much higher than otherwise would have been. But it will also be a very orderly growth in our pace of development as we have to put in place in the years ahead, a considerable additional infrastructure.

And maybe just the last one, around the Horn River. So I understand the comments around scaling back activity levels a little bit, but what does 2011 look like, just sort of your activity levels from the Horn, and where would you expect to exit '11?

Mike Graham will provide some insight at that.

We're a little bit light, we talked about on our production coming out of the Horn River. So we averaged in 2010 at about 29 million cubic feet a day, and we're hoping to be about 50 million cubic feet a day. We're probably a little over 75 million cubic feet a day now out of the Horn River. The wells are performing wonderfully. The beauty of the Horn River is that we really do have a low decline or much lower than most shale plays in North America. And we still think we can get estimated ultimate recovery on a per well basis right up to 15 Bcf per well, which is really quite amazing. So it's good that way. For 2011, our capital, we have a partner, 50% partner with Apache there. So we think we're going to probably scale back our program a little bit there, but still a sizable program. And we would expect to average somewhere around a little over 100 million, about 110 million cubic feet a day for 2011.

Is that net, Mike?

Yes, all those numbers are net.

And what do you think the exit looks like in '11?

Well, it'll somewhere north of 180 million. It's probably somewhere, we said to close to 200 million in the past, but I don't know if it will be quite that high if we scale back a bit. But it's still probably north of 150 million cubic feet a day, net again.

Your next question comes from the line of Mark Polak with Scotia Capital.

Question for Jeff on the Haynesville. As you start to move into the manufacturing process, would you also be doing a bit more work on the Mid-Bossier and trying to get both sections?

Yes, absolutely. Across EnCana's land base in the Haynesville, we see tremendous potential in the Mid-Bossier. And certainly as you move south and west across our land base, the quality of the Mid-Bossier reservoir increases. And when it comes to the land retention strategy, our primary objective was to save the land. But we haven't done as much work as we would have preferred or like to have done in the Mid-Bossier. But I think moving forward, we're going to move towards an equal effort in regards to production out of the Mid-Bossier.

And then you guys had mentioned last year at the investor day that you planned at some point to test the 40 acres basin. Have you had a chance to do that yet, given the land retention program, or are any plans coming up to try that out?

The gas factory results that I've mentioned earlier in my comments were on 88 respacing. That's the tightest we've drilled to date.

And any plans to test 40 in the near future, or is that further down the road?

Thank that's further down the road. I think when we look at our inventory, we have a lot of 80-acre drilling do before we have to worry about down spacing from there.

Your next question comes from the line of Andrew Potter with CIBC.

Just a question on gas marketing. When these assets become jointly operated, I guess you've marketed the gas together, and I guess the second part of that question is, can you comment at all in terms of the interest or PetroChina's interest in terms of LNG exports, and whether you guys would participate in that if they did decide to go that route?

Our current agreement specifies our allowance EnCana to market the gas for up to the first five years, and then after that period of time, PetroChina would be responsible for its own. We fully expect that they will advance their capability much sooner than that. In the longer term, they have expressed a desire to be involved in the North American LNG market, but we have not discussed any details of that at this point in time. We are, of course, very interested in the expansion and the creation of an LNG export market from North America. And we do think it makes a tremendous amount of sense for that market to be linked to the Asian market from a proximity point of view. And so we look forward to supporting that in any way we can.

And then one other question if you could maybe comment at all on the potential size of other JVs. I mean presumably, we're not looking at another $5 billion deal. But maybe a little bit of color roughly on how they big they could be. Then specifically the Horn River, I think you'd mentioned you've been discussing with Apache to split up the JV lands, and I guess how that's proceeding? And is that a barrier to doing JVs in the Horn River as it stands right now?

There's a lot of questions there which we don't have, I'd say, a lot of answers at this point in time. We are exploring the possibility of doing additional joint ventures on significant parts of our land base. We do like to have a fairly good understanding of the value of the place before we put them out. But we are sort of testing it right now in terms of what we might be able to do on a number plays, both in Canada and the United States. I would say, though, that because of the deals that we've already put in place, both in Canada and the United States, they have generally met our longer-term objective. And so, our speed at which we might enter into more agreements might be more paced at this point in time.

. Your next question comes from the line of Ross Payne with Wells Fargo.

On the payment of the $5.4 billion, my first question is, are there any performance parameters related to earnings of $5.4 billion?

There are no performance parameters. Basically, PetroChina has the option of paying the entire amount upfront or to have some of it paid over time. But at this point in time, we're not able to provide the details of that. But the PV of it, basically, it's the $5.4 billion.

So it could be lower?

Your next question comes from the line of Brian Singer with Goldman Sachs.

Can you speak more specifically regarding the breakout of oil versus gas versus NGLs you're seeing in the Collingwood and on the Piceance Basin and the Niobrara? And any additional color on the well results and well costs you've seen so far?

Probably not. I'm going to turn that over to Jeff. The Collingwood, it's really early days. We just know the characteristics of the reservoir, and we have had some results that indicate some liquids-rich in oil areas, but not enough to provide us with the ability to make any predictions. And I'd say in the Piceance Basin, I'll turn it over to Jeff to answer.

Brian, it's Jeff. Yes, Randy's absolutely right on the Collingwood. We're still cutting cords and trying to understand the reservoirs in Michigan, in the Collingwood. It's a very underexplored area, and very in its infancy from an understanding point of view by the industry and by EnCana. In the Piceance Basin, it's the same thing, like the amount of information that we have to date in regards to the basin itself from a liquids content point of view is something that we're trying to understand. So I think there's more to come on that. I talked earlier in my comments that we drilled a few wells to date gathering information. And I think on the first half of the year, we'll be gathering a little bit more information to answer specifically that question that you have. And I think the economics and the opportunity that present itself in that basin are very much a function of liquids content moving forward. So more to come on that.

And then when we think about a more big picture, how material do you see your liquids production becoming based on what you know now about our portfolio, and how willing or you to consider making acquisitions that could add liquids exposure or frankly gas for that matter, given that you used to have a stronger balance sheet post closing the PetroChina JV?

What we'll do is, of course, look at our interpretation of the risk return associated with any acquisition we make, whether it's a land acquisition or property acquisition. And we'll also look at what the risk return expectation is in any exploration activity that we undertake. We do know that we have some fairly significant potential on our lands for liquids-rich plays. But we are, again, at a very early stage on many of these plays, and results from our own activity and from other industry activity will probably give us a better sense of what the potential is, I would say, even as this year unfolds. So it maybe a little bit early right now, but I think the potential is significant in the future.

Just following up on the last part of the last question. You mentioned that PetroChina has the option to potentially pay the $5.4 billion over time. Can you just add a bit more color as to when that decision needs to be made, and what is the longest period over which you would receive the proceeds?

I can't really provide that detail to you right now. But it's a portion of the $5.4 billion can be paid over time. And that decision will be one that PetroChina will have to make. And I expect that they won't make that decision until closing.

Your next question comes from the line of Mark Gilman with The Benchmark Company.

Can you give me an idea of what the year-end inventory of wells yet to be completed was, split by division?

I think Jeff and Mike have that information with them. I'm not sure if they do, but --

Mark, I don't think in wells, I think in months. But in several places where we are sure of the completion services like the Piceance Basin and the Haynesville, we have -- I think in the Haynesville we have several months' wells, which is maybe a little bit longer than we'd like to carry. And in the Piceance, I think we have four or five months of inventory. So at a regular pace. But specifics, I can get back to you on.

I think what we're really saying is, we did get backlogged little bit in the Haynesville and in mid-year, and Piceance Basin may be a little bit later in the year.

And on the Canadian side of the border, Mike?

We don't have a lot as well, Mark. We've probably got somewhere in the order of 50 to 70. But I can tell you in our CBM, we really had, I think, a lot of operating, as we were talking about, wet weather we had in Alberta over the summer. So we really got sort of backlogged. But in the last part of the year, we actually drilled about 600 wells in CBM. And that production is starting just to come on as we speak here over the next quarter or two. So we're seeing very strong volumes out of our CBM now and should have a great year and in 2011.

So Mark, sort of the answer to the broader question is that we were seeing some equipment -- seeing some completion equipment shortages in the U.S., which we are in the process of resolving. In Canada, it was more of a weather-related issue.

Randy, can you give me an idea how much Duvernay acreage you acquired, and at what cost?

I'm going to give that to Mike Graham to answer.

Well, Mark, I tell you, it was actually a pretty good year to buy land in Canada. And we bought a lot of land in the 500,000 net acres at a cost of about $650 per acre. Like Randy alluded to, a lot of that is on liquids-rich plays, plays like the Duvernay areas and the Montney where there's a lot of liquid areas, and the Deep Basin of Alberta, the well rich and the Fahler. So we're really adding to our land position relatively cheaply. We're not specifically seeing our increased position in the Duvernay. It is very material to EnCana. And we're out there, we drilled the well into an island. And we currently have the well on test. So we're not going to say too much until we probably get out of the first quarter.

Randy, it occurs to me that there are certain elements of establishing the arrangement with PetroChina where the interest of the two parties may not be entirely congruent, relating to activity levels, relating to dividends back to respective parents, potential problems and issues on a 50/50 type arrangement. Can you talk a little bit about what you're thinking is on that subject, and how it would be handled?

Well, whenever we have joint venture arrangements, we always have to deal with those kind of general issues, not maybe not the dividend one, which I haven't really thought about. I don't necessarily think it applies either. But with respect to -- the biggest issue is always about the pace of development and then the respective size of the capital program. And we're very fortunate to be doing this deal with PetroChina, a very financially strong corporation. And because this is one of the lowest-cost plays in our portfolio, it's the one that's most likely to attract an investment. So in that regard, I think we're fairly aligned. We both believe that this property has tremendous resource potential and has the potential to grow at a significant rate. We may not be fully aligned ever on what our expectations are going to be for North American natural gas prices and such. But I think in many areas we're going to have a fairly strong alignment. And when these are the kind of issues over the next six months as well. We will have to start putting them into the operating agreements.

Can I ask you how you're going to account for the joint venture on the books? Is there going to be equity, it proportional consolidation? What are you going to do in that regard?

I'm told it's proportional consolidation.

Your next question comes from the line of Phil Skolnick with Canaccord Genuity.

The 250 million cubic feet a day that PetroChina is getting, is that included or excluded from guidance? I guess the question is that your production CapEx you put out for '11 to date, is that going to be adjusted when this deal closes?

Our guidance is, with respect to the current business and should we be successful in closing the deal with PetroChina, then we would make a new adjusted guidance at the time.

So does that mean we could maybe see increasing CapEx spending at all?

It means that pretty much everything is open at that point in time. We'll probably give more guidance on number of outstanding issues.

[Operator Instructions] Your next question will come from the line of Amanda Fraser with allnovascotia.com.

You'd mentioned that the PFC won't arise in Nova Scotia until Q3, why is that?

Mike Graham here, Amanda. Maybe just to talk about Deep Panuke, we completed our pipeline to shore. We completed our drilling and completed programs, so everything is pretty much done there. What we know in terms of our capital increase, we've gone up a bit in capital numbers, we think about $960 million overall. It's up a little bit about 20% kind of from where some of our original estimates in 2008, 2009,. FX weather delays and a few other issues on there. So not too bad overall. The production field center is getting very close to being done. It's like 95% done in Abu Dhabi, and there's been a sale out of the Middle East here in about six weeks. So it's coming our relatively quickly, and I think it takes 40 or 50 days to get over the Nova Scotia. So it's coming real quick. We do expect to get first gas production in the second half of the year. We've actually budgeted for it to start-up in Q4 of 2011. And we're excited to see production come over. We're going to bring it on in about 250 million cubic feet a day, which is around our full capacity on Maritime Northeast. But it'll be actually able to flow if there's interruptible space in the pipe, maybe right up to close to 300 million cubic feet a day. When we tested the wells out there, Amanda, and there are no surprises, all the production wells looked very strong. So we're excited to see production coming on here in the second half of 2011.

And you also mentioned, too, that you are budgeting $100 million to spend in 2011. What will that be for?

Most of the costs, like I say, Amanda, are complete now. Really, all we have to do with it is hook the well up to the production fuel center. So that's about it. It's just the cost to hook the wells up to the production fuel center. So out of the $960 million, only $100 million more to spend.

The fact that it's not going to arrive here until Q3, does that leave enough of a window in the first half of Q4?

Yes, David Tomlinson [ph 01:22:34]says yes, that will be the case. So we're pretty darn comfortable that we can we'll have gas flowing in Q4 of this year.

Your next question comes from the line of Carrie Tait with Globe and Mail.

In the press release and today, EnCana had said that it will be the operator of the project, it will be the initial operator of the project. I'm wondering if you can sort of explain why it's just initial, how long that initial period will be, and if that means PetroChina could eventually take over?

Initially, EnCana will continue to operate. And in the long term it will likely be EnCana people that are dominantly part of the operating team. It doesn't mean that -- it'll be operating basically under the guidance of a management committee, represented 50% by EnCana and 50% by PetroChina. It's really just trying to explain that after a couple of years after closing the deal, we will evolve into a new sort of corporate form, which has not really been disclosed yet nor fully discussed.

And my second question, when Sinopec invested in Syncrude and when KNOC bought Harvest, both of those companies had to make spending commitments to the federal government to get approval, some as far as 10 years out. I'm wondering if PetroChina has its spending commitments in line, and how they fit into this deal?

I'm certain those have not been discussed at this point in time.

They haven't been discussed with EnCana?

They haven't been discussed, I would say, with anybody at this point in time. So we'll be just filing our application for investment in Canada shortly.

And my final question is, with the initial prediction that EnCana would strike joint ventures between $1 billion and $2 billion per year, I'm wondering why EnCana went so far beyond that this time and has and continues to pursue joint ventures?

The $1 billion to $2 billion per year, I was talking at that time in reference to a five-year plan. And so that would be between $5 billion and $10 billion of third-party money coming into the corporation. So this represents a significant portion of that, it doesn't represent all of that. And at that time, it wasn't anticipated that we would have a sale of production as part it -- so you have to kind of back that up, too. So the part which is really part of the joint venture deal is a bit smaller, although I can't provide you with those exact details. But back to your first question, Carrie, our anticipation is that there's going to be a substantial amount of expenditures made by both Encana and by PetroChina and that we will have -- that the level of expenditure will be much higher than it would've otherwise been had EnCana just been developing the assets on their own.

So just to clarify, you expect EnCana will spend more now than that it has a partner rather than developing on its own? Is that because of the pace of development?

What I'm saying is in aggregate, it'll be significantly more, whether or not EnCana spends more now that we have two 50-50 partners in the deal. We expect that it will build to a much higher rate of investment at a faster pace of development than we would have otherwise done on our own.

Oh, spending on the project rather than on EnCana's spending?

Right. I can't comment on EnCana's spending specifically.

So is the $5 billion to $10 billion of joint venture over five years, is that still sort of the goal?

It certainly is something we are thinking we have the opportunity to do. Relative to what we've done today or what we have done in the past in aggregate what we've done today, we've substantially achieved that target already. And so, our belief is that we have an opportunity to do quite a bit more in our portfolio. But not all of the opportunities that we would like to conduct joint ventures on are at the same state of maturity and we think the value recognition, once you get to a higher state of maturity, is a better proposition.

Your next question comes from the line of Tonya Zelinsky with Upstream International.

I just want to touch back on what was discussed earlier regarding LNG, and I'm wondering what role LNG played when looking at potential exports and making this deal with PetroChina. Were you looking ahead and thinking this would be something that could be viable, working this deal out?

We think it will be an interesting additional component to the deal. We've talked about the need for export LNG capacity in North America since the recognition of the abundance of natural gas in North America and the acknowledgment that we have multiple points of import for LNG, but no real export points for LNG. And to make the market more fluid and functional, we think it needs both. And we think there is now, a capacity from the resources that exist in North America to have a substantial amount of LNG on the continent. And more specifically, we think there's an opportunity with Asian players who demand more natural gas in their energy portfolios.

How far ahead into the future are you looking with this? Do you have a tentative timeline in place?

Realistically, to bring additional LNG into North America, you've got to be looking at five-year sort of time frames for the first ones and 10 to 20 years out, we guess if you'd like to have a significant quantity in North America.

Your next question comes from the line of Elsie Ross with The Daily Oil Bulletin.

To follow-up on the LNG question, would you be looking at providing getting some sort of access to the Kitimat project?

There's obviously an opportunity to supply natural gas to that project. We haven't been in specific discussions with that at this point in time.

So it's something you'd be pursuing?

We're looking at LNG across North America, so of course we'd be looking at that.

And the other question is, just a really sort of basic little question. How many CBM wells are you going to be doing in Canada this year?

Mike Graham here. We did actually drill about 1,044 CBM wells in 2010. So we were actually very active in CBM. We had a great program and it still continues to compete nicely in our portfolio. So right now, we haven't actually set our capital -- -- well, we have set our capital budget, I guess, but we haven't figured out each and every one of our resource plays. So it will probably somewhere in that level, maybe just a take down from that. But I can tell you over the last several years, we've been very active in CBM, anywhere from 500 to 1,000 wells a year. And we think we have an inventory of somewhere around 16,000 wells that we could drill in CBM still.

Just mainly Horseshoe Canyon?

Yes, that's right, Elsie. Essentially, all of them are in Horseshoe Canyon. We are doing some small pilots in the Mancos as well.

Your next question comes from the line of Marcus Earnish [ph] with Calgary Sun.

I'm sorry to belabor this LNG business, but Randy, could you perhaps tell me what role, if any that eventual gas exports to Asia play in reaching the deal in PetroChina? Was it part at all of your discussions?

It wasn't part of our discussions at all, although I fully understand and appreciate the desire for PetroChina to link up with LNG in North America.

I'm just trying to figure out that PetroChina's rationale. Are they trying to gain expertise by partnering with you, or is it the export opportunity of gas to Asia? But I guess that's the question to best ask PetroChina?

I think you've answered that.

At this time, we have completed the question-and-answer session, and we'll the turn the call back to Mr. McRitchie.

Thank you, everyone, for joining us today. Our conference call is now complete.

Ladies and gentlemen, this concludes today's conference call. You may now disconnect.