Ryder McRitchie - Vice President of Investor Relations Randall K. Eresman - Chief Executive officer, President and Director Sherri A.

Brillon - Chief Financial officer and Executive Vice-President Robert A. Grant - Executive Vice President of Corporate Development, EH&S and Reserves Jeff E.

Wojahn - Executive Vice President and President of USA Division Michael G. McAllister - Executive Vice-President and Acting President of Canadian Division Eric D.

Marsh - Executive Vice-President and Interim President - Canadian Division Unknown Executive -

Greg M. Pardy - RBC Capital Markets, LLC, Research Division Andrew Potter - CIBC World Markets Inc., Research Division Mark Polak - Scotiabank Global Banking and Market, Research Division Michael P.

Dunn - FirstEnergy Capital Corp., Research Division George Toriola - UBS Investment Bank, Research Division Robert Brackett Robert Bellinski - Morningstar Inc., Research Division Brian C. Dutton - Crédit Suisse AG, Research Division

Thank you, operator, and welcome, everyone, to our discussion of Encana's first quarter results for 2012. 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 39 of Encana's Annual Information Form dated February 23, 2012, 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. Encana reports its financial results in U.S.

dollars. Accordingly, any reference to dollars, reserves, resources or production information in this call will be in U.S.

dollars and after royalties unless otherwise noted. In addition, for the first quarter of 2012, Encana adopted U.S.

Generally Accepted Accounting Principles for financial reporting purposes, referred to as U.S. GAAP throughout this call.

In 2011, the company prepared its financial statements in accordance with International Financial Reporting Standards, referred to as IFRS. The adoption of U.S.

GAAP has not had an impact on the company's operations, strategic decisions or cash flow. Full year 2011 and 2010 reconciliations between IFRS and U.S.

GAAP are available in Note 27 to the company's annual consolidated financial statements prepared in accordance with IFRS. In addition, the company has prepared supplemental U.S.

GAAP financial information, including Encana's 2011 annual consolidated financial statements and selected 2011 quarterly financial information, which are available on the company's website at www.encana.com. In an effort to better utilize your time on the call this morning, we have opted to condense the comments provided by our executive team before opening the call up for questions from the investment community and media.

We have assumed that everyone on the call has read the news release issued earlier this morning. Randy Eresman, Encana's President and CEO, will speak to some operating and financial highlights for the quarter and provide an update on Encana's outlook for the remainder of 2012.

At the end of the prepared remarks, our leadership team will 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 this morning. During the first quarter of 2012, Encana continued to generate strong cash flow despite further downward pressure on natural gas prices, which, toward the end of the quarter, was approaching the lowest levels in the last 10 years.

We generated cash flow for the quarter of over $1 billion, supported by our strong commodity price hedging program. Responding to the low natural gas price environment, I indicated during our year-end conference call in February that Encana would immediately take action to restrict or shut in about 250 million cubic feet per day of production after royalties.

Our teams have determined where and how to best achieve the target, and we currently have in place voluntary capacity reductions, volumes that have been shut in or otherwise curtailed, which should enable us to meet that target. The duration of Encana's capacity reductions is subject to a number of factors, including a recovery in natural gas prices, and that remains uncertain at this time.

In addition to physical capacity reductions, our reduced capital investments in drying natural gas programs is expected to lower 2012 natural gas production by about 250 million cubic feet per day from our 2011 levels after royalties. The combined total natural gas volume reduction would remove about 600 million cubic feet per day off the market when royalty volumes are also taken into account, meeting our commitments as outlined in our guidance.

While we're slowing the pace of development of our dry natural gas assets, we are accelerating production from our oil and liquid-rich assets. Liquid production volumes during the first quarter grew to an average about 29,000 barrels per day.

The impact of increased liquids extraction from deep cut facility expansions in Western Canada, as well as expected organic liquids production growth from our portfolio of oil and liquid-rich plays leaves us well positioned to achieve our guidance target of 28,000 barrels per day for the year. Today's news release provides details on some of the encouraging results we've seen from plays such as the Tuscaloosa marine shale, the Eaglebine, the Michigan, Collingwood, Utica and the Duvernay shale.

Our plan is to drill approximately 40 to 45 assessment wells in the first half of the year across our portfolio of emerging oil and liquid-rich plays. Currently, we're about halfway through that drilling program, and we plan to have more comprehensive well results from each of these plays to share with you at our Investor Day in June.

But I'll say that we are very encouraged by the results we've seen so far. Our teams have effectively applied the technical knowledge and operating efficiencies used in developing our historical natural gas assets in these highly prospective oil and liquids-rich plays.

For example, transferring the knowledge we gained in the -- developing the Haynesville Shale, we recently drilled our fourth well in the Tuscaloosa marine shale to a total horizontal length of almost 9,000 feet. It took 3 years before we were able to accomplish that horizontal length in the Haynesville.

We're well on our way to achieving our goal of continuing to drill longer horizontal wells while optimizing our supply chain activities and reducing our cost structures. In addition to the encouraging results we saw during the quarter from our emerging liquids plays, we also achieved very strong results from our more established Western Canadian liquids-rich plays at Kakwa, Redrock and Pipestone.

We expect production from these areas to continue making a significant contribution to our organic liquids growth over the next several years. We're also very pleased with the progress we've made so far this year in advancing several joint ventures and partnership opportunities.

Most notably in February, we announced the closing of our Cutbank Ridge Partnership agreement with Mitsubishi. Our relationship with Mitsubishi is progressing very well, and to date, we have drilled a total of 11 wells on the Cutbank Ridge Partnership lands.

Mitsubishi's investment facilitates the development of Cutbank Ridge, a well-delineated asset where we have several decades of drilling inventory and accelerated recognition of the value inherent in this tremendous, well-defined resource opportunity. We think this transaction provides an excellent analog for what we expect to be able to achieve in several of our other established resource plays, which may also be linked to LNG supplies.

We're currently exploring the potential for an additional transaction with respect to the sale of an approximately 10% interest in the Cutbank Ridge Partnership. A formal process is underway, and I expect to provide an update on this progress later in the year.

Our partnership with Mitsubishi represents one example of how third-party capital can be effectively deployed to create value for our shareholders. The general 3 reasons behind our motivation to engage in joint ventures.

First, to accelerate the value recognition of assets, which we have clearly defined, proven low-cost inventory -- sorry, where we have a clearly defined proven low-cost inventory as we did with Mitsubishi. Second, to help de-risk our early stage capital exposure in new unproven plays; and third, to maintain capital and operating efficiencies on our more mature assets.

The 2 recent examples of this third scenario. We recently entered into a joint earning agreement with Exaro Energy, which provides funding of up to $380 million to continue developing -- drilling in the play.

This transaction, in addition to the joint venture we announced last year with Northwest Natural Gas, produces Encana's capital requirements in the play while maintaining an efficient development drilling program. Having a dedicated 4-rig drilling program at Jonah will provide enough steady work for one completions crew without sacrificing the economics of scale we have achieved through our resource play hub development model.

Similarly, the agreement we announced last week, which will see Toyota invest approximately $600 million in a portion of our coal bed methane resource play to earn a 32.5% gross overriding royalty, will help maintain capital and operating efficiencies on one of the lowest cost, lowest risk assets in our portfolio. In addition, it will also help to preserve our supply chain management initiatives and retain our intellectual capital.

These agreements serve as a model for other investment opportunities available across our portfolio of assets. Delineating the potential of our emerging oil and liquids-rich lands is amongst our top priorities for 2012.

In an effort to accelerate the development of certain early life oil and liquid-rich plays, we announced during the quarter that we are seeking joint venture opportunities on a group of emerging oil and liquid-rich plays located in the United States, which comprise approximately 1.2 million net acres, as well as joint venture opportunity in the Alberta Duvernay shale, which covers approximately 370,000 net acres. We believe that engaging in joint venture opportunities on these early life assets will be very effective in helping to reduce our capital exposure and accelerating the evaluation and potential commercialization of these assets, ultimately increasing our pace of liquids growth and de-risking the portfolio plays.

While it's premature to speculate on the size or value of any of potential transaction, it is our intention in marketing an interest in these assets that Encana would continue to be the operator and retain majority ownership. We're targeting to complete a joint venture on these assets by year end.

Diversifying our production profile by increasing the weighting of oil and natural gas liquids is driven by the very large differences between oil and gas prices and by our desire to invest in our highest return projects. While many of our assets in our dry gas portfolio are still economic at sub-$3 NYMEX prices, the results -- the returns of those projects may not be as attractive as those in our oil and liquids-rich opportunities, the cost structures of which are still being evaluated.

Additionally, having a predominantly gas-weighted portfolio has exposed our cash flow generation to more risk than we would like. As such, achieving a more diversified commodity mix addresses some of the impact of currently depressed natural gas prices while increasing the resiliency of the company over the long term.

Furthermore, when natural gas prices do improve, it is not our intention to flood the market with gas in response to a modest increase in price. We will need to see sustained prices in a range that provides competitive returns with our oil and liquids investments and which are more reflective of the marginal cost to supply, which we believe is in the range of $4 to $6 per 1,000 cubic feet.

Once natural gas prices return to a more sustainable level, we believe that Encana's shareholders will benefit more from the impact of higher natural gas prices on our base level of production than from increasing natural gas production at an aggressive pace. We see significant opportunities for oil and natural gas liquids developments in our current portfolio of assets.

Going forward, we believe Encana will essentially have 3 distinct and meaningful businesses focused on natural gas, NGLs and oil. While the market drivers for each commodity are very different, the technology and operational efficiencies required to develop each type of assets are the same.

We have tremendous breadth and depth in all of these 3 businesses, and we are eager to showcase Encana's expertise and resource play development across our portfolio of promising new oil and liquids-rich plays. As we look ahead to 2013, management is committed to maintaining Encana's balance sheet strength and financial flexibility.

We have fortified our balance sheet, building a cash position of approximately $2.4 billion as of the end of the first quarter. We're currently targeting to have approximately $3 billion in cash and cash equivalents on our balance sheet by the end of the year.

This target will continually be addressed through the year and is dependent on a number of factors, including commodity prices, the success of our 2012 oil and natural gas liquids program and the completion of additional joint ventures or asset divestitures. This cash reserve will help ensure that Encana's balance sheet is well positioned to weather the low natural gas price environment, should it persist through 2013.

So looking at natural gas prices. We're cautiously optimistic that we could see the beginning of recovery towards the end of this year or into 2013.

This view is based on a combination of factors. On the demand side, we've seen an increase in coal-to-gas switching.

Over the last 5 to 6 months, the equivalent of 7 billion cubic feet per day of coal-fired generation has been displaced by natural gas. This current displacement could become permanent natural gas demand as 50 to 60 gigawatts of coal-fired generation are expected to be retired by 2025.

This will be the equivalent of about 6 billion to 8 billion cubic feet per day. Additionally, this spring, we're seeing a decreased snowpack in the Western United States, which could lead to less available hydro-electrical power generation.

We think this could result in additional natural gas demand of up to 1 billion cubic feet per day for the remainder of the year. On the supply side and in addition to the capacity reduction initiatives that Encana has undertaken, we're estimating that the industry-wide shut-ins in North America are currently in the range of about 0.8 billion to 1 billion cubic feet per day.

While shutting in production helps to address the near-term storage overhang, a sustained price correction will be dependent on producers investing significantly less capital in dry gas assets. Since the beginning of the year, most of the major North American natural gas producers have announced significant funding cuts to the dry gas programs.

Based on our expectations that the dry gas directed rig count will continue to fall over the next several months. We expect to see a decline of production in the later half 2012 and 2013.

The uncertainty around the near-term supply-demand balance rests with the level of associated natural gas production from liquid-rich plays and the effect those volumes will have on offsetting declining dry gas production. We're working to improve our internal understanding of this and the impact it will have on North American natural gas supply levels.

We’ll likely be in a position to provide more details at our Investor Day. In the long term, we believe that North American natural gas prices will be supported by exporting LNG to world markets.

The LNG market is evolving rapidly as several proposed North American expert facilities continue to advance in regulatory approvals -- advance through their regulatory approvals. In addition to our direct involvement as a 30% owner of the proposed Kitimat LNG export terminal, we also believe that many of our assets are ideally suited to provide feedstock for other proposed LNG terminals in Western Canada and the U.S.

Gulf Coast. So despite the historically low natural gas prices we're currently enduring, I'd like to reinforce that we at Encana continue to believe that the long-term future for natural gas remains very promising.

However, during the current period of extended low natural gas prices, we have taken steps to retain our financial flexibility, slow our pace of dry natural gas development and restrict production from some of our dry gas wells. At the same time, we continue to allocate more capital oil and liquids-rich opportunities and attract third-party capital to unlock the value for our enormous reserves and resource base.

Until we see signs of a sustainable recovery in natural gas prices, we'll continue to focus our efforts on creating value from our very promising suite of oil and liquids-rich assets by applying the same technical knowledge and operating expertise that has earned Encana's reputation as an industry leader in the development of natural gas resource plays. We're very optimistic about the prospectivity of these early life liquids plays, and I look forward to updating you on the progress of our drilling programs as the year unfolds.

Thank you very much for joining us today. Our team is now standing by to take your questions.

Just, I guess, a couple of nitty questions and then one broader, but just interested in where you think your cash tax recovery would shake out this year at the -- just at your budget of pricing. And then as it relates to the liquids rich JV, just curious as to whether a data room has been opened and so forth at this stage.

And then lastly, Randy, is there any color you can provide around the Tuscaloosa, other than what was in the press release?

Okay, I'm going to get 3 people to answer the question. I’m going to get Sherri Brillon to answer the cash tax question, and then I'll have Bob Grant -- okay, I'll have Bob Grant answer the liquids question, the JV and, afterwards, I’ll get Jeff Wojahn to answer…

Okay, thanks, Greg. We're currently estimating an income tax recovery for the year of about $300 million, and this would include the transactions that have closed as of March 31.

As you know, this current tax recovery estimate is going to be impacted by our future divestitures and JVs and some other changes in estimates, including our changes to cash flow, should price change through the year, and we'll update this each quarter.

Okay. And Sherri, is that at $3.25?

Or would that be sub $3.25?

That would be at $3.25 for the first quarter and then the forward curve thereafter.

Bob?

Yes. On the liquids processes we have underway, on the Duvernay, we plan to -- we have hired advisers.

We have RBC on board, and we are currently preparing teasers and should have a data room open in late May or early June. Kind of the same thing in the United States, we have Jefferies on board looking at those opportunities in the United States.

So relatively the same timing on that.

And on the Tuscaloosa, Jeff, can you provide some color?

Yes. Right now, our primary focus in the Tuscaloosa is an appraisal across our over 300,000 acres of the play.

So really, we're in the initial appraisal steps of drilling wells. We're really looking to step out.

The 3 wells that we've drilled so far have crossed our land base. In fact, I think the step out from the original Weyerhaeuser to the second or third wells is about 20 miles step out.

So really what we're trying to understand right now is the characteristics of the reservoir to have some initial best estimates of drilling and completion practices that would be most suitable. Obviously, we're using a lot of knowledge from the Haynesville program and trying to incorporate it into Tuscaloosa.

The next steps following will be to continue to appraise the overall land base and start focusing more of our efforts around longer horizontals and more optimization around our completion programs, and that's kind of our work in the upcoming months.

Okay. And maybe just a couple of follow-ups on that.

I know -- I think in the fourth quarter, you didn't feel as though the well costs were all that representative. But do you have a targeted well cost right now?

And curious how many fracs that would be. And then secondly, just -- I know you’ve provided 30 day IPs.

Have you generally found those rates to be shallow decline? Or have you found that the rates have come off sharply?

I'll start with our goals. I think our goals are to drill the longest, the most cost-effective horizontals with the most effective completion strategies that will ultimately allow us to maximize the EURs or recoveries from the wells, and that's a process that we've just started.

So we mentioned today that we drilled our last horizontal nearly 9,000 feet, and we have an internal goal to drill 10,000-foot wells in the TMS. So we've accomplished a lot.

We're going to go through a design -- we call it a design of experiment to optimize our EURs around fracture stimulation, and that work's ongoing right now. We will talk a little bit more about the EURs and the capability of the wells.

But right now, as I said, we just have a lack of long-term data. So it's premature for us to get into the details of the EUR.

But hopefully, as I said, by June, we'll have more details around that.

Okay. And I suspect the same goes into the IPs.

You'd rather wait?

Well, our IPs in the first 3 wells, I think we've disclosed those, have been in the 500 to 800 barrels a day. But that's really all the data we have, so it's premature to start talking about type curves at this time.

Greg, well costs on all these new plays tend to be quite a bit higher at the beginning as we're doing a lot of experimentation, and we're also getting a lot of additional data collection, of course [ph], other forms of data. And it'll take us a few more months before we're able to project to what the real cost will be once we get into resource play development mode.

I have one piece of information. In the Haynesville for the long lateral wells, we’ve drilled long lateral 7,500-foot horizontal wells in the $12 million to $13 million range.

So that's something that we demonstrated to ourselves that we know we can do in a resource play hub manner, and that would clearly be one of the steps that we'll be looking at is to take those learnings from the Haynesville and apply them to the Tuscaloosa.

Okay. And the last one, I guarantee, for me, then there's no -- in terms of drilling the longer laterals, whereas in the Haynesville, obviously, there's 100% land owner agreement.

There's -- really, are there any limitations that way in this case with what you're doing in the Tuscaloosa?

In Louisiana, we just -- we received a new ruling that will allow it easier to establish longer -- larger units to drill longer wells. And I think that's very important because half of the Tuscaloosa play is in Louisiana.

In Mississippi, I believe the spacing that is defined or can be defined is 9 to 60 acres, which would allow you to currently drill 7,500-foot long horizontals.

Just a question on the Duvernay, first of all. I think you talked a little bit about liquids content being fairly similar to other wells that are being drilled by industry in the area.

Assuming we can also make that connection on initial productivity rates or maybe just a little color around that.

Yes, Mike McAllister's going to answer.

Yes, we've seen -- or we have one well off of confidential. It’s a vertical well in the Duvernay, and we've seen liquids content up to 300 barrels per million, so -- as well as the gas rates are also commensurate with whether the wells have off or public in the Duvernay as well.

So that's -- I guess, it's consistent.

And then just one question from an overall guidance perspective. Maybe you can just give us a little color in terms of where you expect to exit 2012, given the decline profile and all that sort of stuff.

Sorry, are you talking about natural gas rates or oil rate?

More the natural gas side, I guess, but both if you can give them.

I think we're likely to be pretty flat through the year, and one of the reasons for that is because in the second half of the year, on -- sorry, on the natural gas side, we're relatively flat because Deep Panuke will be coming on later in the year, and that will support the otherwise the declining production that would have occurred. On the liquid side, too early to make a prediction on that, but we hope it exceeds our guidance.

And just one last question, just sort of from a transaction perspective. I mean, when we sit back and look at all the deals that you guys have done and other industry JVs, I mean, it seems that buyers are, obviously, embedding a significantly higher gas price into assets than what the market is currently reflecting.

So I mean, you guys have done a lot of kind of one-off transaction deals. I mean, does this sort of open the door or raise the possibility of just an outright corporate sale as opposed to just continuing to do one-off deals and monetizing the value that way?

Well, we think that there's a tremendous amount of value in our existing resource plays that we would like to unlock individually.

Pretty nice jump in liquids production for the quarter. I was just wondering, is that largely from Musreau plant coming online?

And if so, then should we sort of think about that being sort of flat throughout the year until later in the year when Gordondale comes on?

Mike McAllister, I think you've got oil production gains in several of your areas.

Yes. So of the liquid gains you saw, which I think was in the neighborhood of -- in the Canadian division, about 5,000 barrels a day, half of that came from the Musreau start up.

So NGLs and the other half actually came from royalty interest oil in the Clearwater business unit. So it's half oil, half NGL.

And I think we see that being fairly flat here through the remainder of the year.

Just thought I would ask, as you're sort of entering or seeking more joint venture type of arrangements on your assets and with the deals that you've done to date, what sort of agreements are in these deals regarding capital flexibility? I mean, obviously, the more deals you do and, certainly, if you can do these deals at significantly higher multiples than what the market's paying in your stock, do that all day, I guess.

But I'm just trying to think about the capital flexibility as you -- as a greater percentage of your production is sort in sort of partnership deals, if you could speak to that.

Okay. I guess, there's -- we kind of take that question a couple of different ways.

One would be each of these deals are individually negotiated, and some of them have the ability to reduce capital spending if prices get below a certain point. They basically -- I guess, each deal is kind of unique in the way they're formed.

We are trying to make sure that when we're putting the JVs together, we're putting them together for our mature assets that they're on our very lowest supply cost plays such that these are plays that we would always want to be investing in first.

Two questions. The first is on the shut-in volumes.

Randy, you did talk about sort of things you're doing to get you to 250, I think, was your comment. Could you provide details around the premise for shutting in the volumes and then the -- geographically where that is from?

The general premise is that we think the market has -- is oversupplied with natural gas and causing prices to be lower than the marginal supply cost is in North America today. And so we're shutting in gas in areas where we believe that we will get a higher price for those gas -- for that same gas in the future, which will make up for the loss in cash flow today.

Just as a general rule of thumb for the gas we’ve put in -- shut in so far, we would need about $1 higher in natural gas price to achieve our cost-to-capital rate of return. So that's the general premise and what we need in order to make.

Some of that gas that is shut in, I guess, was going into a storage pool. All of the gas that we're shutting in is coming from places where we're relatively certain that the wells will respond well when they come back on.

That's helpful. I guess, the second question is just as we look out to 2013, and you did sort of allude to what you're doing to keep the balance sheet strong if this weakness persists, would you -- as you look at 2013, would you be looking to leave within cash flow -- so essentially, are you going to not -- are you going to keep the proceeds that you generate here as that, or you could be tapping into that for expenditures in 2013?

And what type of debt-to-cash flow would you be targeting if we see just because if prices go down from here, that ratio may start to climb up.

Right. Was having just a little challenge hearing your question, but I think I have the general idea of it.

We have the opportunity in 2013 to further reduce our dry gas capital expenditures by simply a reduction in our commitments that we have for goods and services, completion crews, drilling rigs, et cetera. However, our preference would be to grow our liquids business through the success of the wells that we're drilling this year.

We would like to add more into the second half of the year in terms of capital spend and, hopefully, have a much higher cash flow coming out of liquids than one would project based on our current level of natural gas and liquids production. The target of $3 billion on our balance sheet by the end of this year is somewhat flexible in that if there is more liquids success, we would consider reducing that amount if we did nothing else but just go forward with our capital program as it stands today.

If we are able to bring in additional cash flow through these liquids-rich joint ventures or other sale of assets, our position would be even more, I guess, improved for 2013. It's a little bit difficult at this point in time to make too much of a projection into 2013 with as many moving parts as we currently have.

But we think we're going to be in pretty good shape regardless.

I had a question on the Eaglebine wells. What's the depth of those wells?

Are you landing them into the Woodbine proper? Do you think you're getting contribution from both zones?

And what's the true vertical depth?

Good questions, and Eric Marsh is going to provide you some insights into those.

Yes. Thanks, Bob.

TDD on those wells is about 6,500 feet to 7,000 feet, depending on where you're at, and we're actually targeting a variety of different horizons as we experiment with our first 5 or 6 wells there. So more to come.

We'll give you more of a detailed review of that at our Investor Day, but overall, very pleased with the initial results.

And the liquids mix?

They're oil plays.

I think it's Morningstar. I just wanted a couple of quick questions.

First, with regard to your hedge program, do you see adding additional hedges in 2013? Or what's the status at this point?

We're optimistic about a potential natural gas price recovery going into 2013. So we see much more upside than downside in natural gas prices.

So it wouldn't be a good time to hedge at current prices.

Okay. And then I saw you broke out production for Peace River Arch.

I was just wondering, what are the development plans for that at this point?

Mike McAllister is going to explain that.

So we’ve split Peace River Arch out from Cutbank Ridge. It's basically better aligned with our Mitsubishi Cutbank Ridge Partnership, which is focused on British Columbia.

The development plans for the Peace River Arch focus in on both Gordondale and Pipestone. We're looking at about, I think, sort of 5 wells in both plays going forward here for the remainder of the year.

I'd just like to revisit the balance sheet question again. You have $2.4 billion of cash on the balance sheet now and with plans to have about $3 billion of cash there by the end of the year.

So knowing that you have the $1.5 billion of debt due in 2013 and 2014, could you give us some insight on how you plan to use your cash balances? And specifically, will you use the cash for CapEx in 2013 if there's no more JVs announced?

Thanks, Brian. Yes, the cash balances would ultimately be used to pay off the debt that's coming due in 2013 and 2014.

But in the meantime, it does provide us with quite a bit of extra flexibility going into 2013.

So if there's no more JVs, would you use that remaining cash for CapEx?

If there's no more JVs, which I don't believe will happen, then I would have to make sure that I have at least $1.5 billion sitting on the balance sheet going into -- by the end of 2013.

So you'd be willing then to use the remainder for CapEx in 2013 if the situation was correct?

That's a 2013 question. That's a little premature.

I was hoping we could just share a few thoughts on Deep Panuke and its summer or mid-2012 production start.

Go ahead, Mike.

Yes. So as you understand, SBM is the operator of the production platform and are working on finishing [ph] that platform.

Their estimate that they provided to us is summertime start up, and we haven't got any updates from them since that point. So we're still looking at a summer start.

And it wouldn't be affected by the efforts to sort of slow production in response to natural gas prices being down then?

We're looking for the best effort to get that production platform started up. We've made quite an investment into it.

Still keen then at this point to see things going as early as possible or summer as SBM has indicated?

Yes. It's from -- definitely from Encana’s standpoint, yes.

In the analyst Q&A, someone asked you whether or not you'd be interested in selling the entire company, and your answer was that you'd like to unlock individually. But you didn't say yes or no.

Does that mean that selling the entire company is being considered?

No, Carrie, it does not mean that we're considering selling the entire company at all. It really means that I believe that the stock price in the company is not -- or the value of the company is not reflected by the stock price.

And we will demonstrate if we need to one play at a time how much value exists in this company, and we believe it to be a great deal more than the stock market reflects.

So that's off the table then?

It's off the table.

How long do you think it will be before people catch on? As you say, you keep selling one piece at a time to show the value of it.

Is there a point where you run out of pieces?

Our inventory is very, very deep.

How long would you intend to sort of keep putting pieces up?

As long as there's an opportunity to continue to demonstrate value.

Randy, I'm wondering if you can just comment on what you're seeing in terms of costs for frac-ing in the Eaglebine and Tuscaloosa. Are these -- as other producers step back, are they falling?

Or are they on the rise as oil producers get more into it?

Thanks, Scott. It's good question.

In our budget this year, we're forecasting very minimal increases in any of our cost structures in the organization. Generally speaking, I think we're pretty flat.

And so that opportunity has, obviously, partially occurred from the fact that there has been a lot of pumping equipment being brought into the industry in the last little while, and there has also been a lot of slow down on the dry gas programs, which is not necessarily been picked up on the liquids-rich programs. So yes, the cost structures are not going up very dramatically this year at all.

Maybe even flat to down.

Randy, I'm just wondering on the additional 10% stake for the Cutbank, would that necessarily go to Mitsubishi? Or are you considering some other third party for that?

And secondly, I was wondering if you could just detail the liquids-rich JVs, the Duvernay, are you doing it for all your -- looking for JVs for all your liquids-rich plays or just certain ones?

Okay. I'm going to have Bob Grant answer the first question.

And on the second question, the plays that are in our liquids-rich JV opportunity right now, just the Duvernay in Canada and in the U.S., we have 4 of our plays that are fairly large in scope, and they include the Tuscaloosa marine shale, the Eaglebine, our Mississippian Lime position, as well as our position in the Collingwood, Utica in Michigan. Bob?

Yes. With respect to the 10% of the Montney and the Cutbank Ridge Partnership, we do plan to broadly market that, and all parties are welcome to attend.

We're looking forward to getting a deal done there, and we think it's a great asset.

Does Mitsubishi have some kind of special right to add to its current stake?

No, they do not.

But we are trying to maintain a very favorable relationship with them.

Just had a quick question on the natural gas shut-ins. Can you give us any kind of a breakdown on the locations as far as where gas is being shut in, how much of it would be in Canada versus United States?

Yes, okay. At this point in time, about 2/3 of the gas that's shut in is in Canada, 1/3 in the U.S.

It's basically all dry gas production. In Canada, I believe it's divided amongst our CBM, our Greater Sierra, Jean Marie play and...

And the dry gas play in the Deep basin.

Okay. And dry gas in the Deep Basin, and in the U.S., it's all Mid-Continent.

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

I encourage you to listen in to our AGM presentation this afternoon. Thank you.