Good day, ladies and gentlemen, and thank you for standing by. Welcome to the Encana Corporation's Third Quarter 2012 Conference Call. As a reminder, today's call is being recorded. [Operator Instructions] Following the presentation, we will conduct a question-and-answer session. [Operator Instructions] Please be advised that this conference call may not be recorded or rebroadcast without the expressed consent of Encana Corporation. I would now like to turn the conference call over to Mr. Ryder McRitchie, Vice President of Investor Relations and Communications. Please go ahead, Mr. McRitchie.

Thank you, operator, and welcome, everyone, to our discussion of Encana's third 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. In particular, I want to draw your attention 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, in 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 2012 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 also prepared supplemental U.S. GAAP financial information, including Encana's 2011 annual consolidated financial statements and selected 2011 quarterly financial information, which is available on the company's website at encana.com. Randy Eresman, Encana's President and CEO, will speak to some highlights for the quarter and provide an update on Encana's outlook for the remainder of 2012 and into 2013. 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, all, for joining us today. On the financial side, during the third quarter of 2012, Encana continued to generate solid cash flow of about $915 million despite lower benchmarked NYMEX natural gas prices that averaged $2.81. Our cash flow is supported by our strong risk management program, and we're on track to meet our financial and operating guidance for the year. Net earnings, a loss for the quarter, were driven by the required recognition of ceiling test impairments. Under U.S. GAAP full cost accounting, the carrying cost to Encana's natural gas and oil properties is subject to a ceiling test on a quarterly basis. In the third quarter, we recorded a $1.2 billion after-tax noncash impairment charge against net earnings. The ceiling test impairments primarily resulted from the decline in the 12-month average trailing natural gas prices. I'd like to highlight that the impairment charge is noncash in nature and is not indicative of the fair market value of the underlying assets. With respect to production, third quarter natural gas volumes were just over 2.9 billion cubic feet per day. In the Canadian division, volumes were lower compared to 2011 primarily due to shut-in production, partially offset by our successful drilling programs at Bighorn and Cutbank Ridge. USA division, volumes were lower compared to 2011, primarily due to divestitures, natural declines and shut-in production, partially offset by successful joint venture drilling program in the Piceance basin. During the first half of this year when natural gas prices were at their lowest in the last 10 years, Encana's shut-in or curtailed approximately 500 million cubic feet per day of production. Beginning in August, Encana began bringing these volumes back online with a goal that all shut-in volumes would be back on stream prior to winter.…

[Operator Instructions] Your first question comes from the line of George Toriola with UBS.

Randy, I've got a couple of questions here. I guess the first is just on Deep Panuke. What's the status of Deep Panuke, and when do you expect volumes to come on stream from that facility?

Okay, I'm going to turn it over to Mike McAllister, who's on top of that project.

George, yes, as you'd understand that SBM, Single Buoy Moorings, actually are the owner, constructor and operator of the platform, the PFC, and what they're saying right now is they're targeting before year end that we would have first gas.

Okay, and how quickly do you expect to ramp up to the 300 million or so capacity?

I think what we're looking at is about a month to go -- to ramp up to the 300 million capacity.

Okay, great, and then the other question is just around the JV. And my question is based on what you've seen so far in terms of response from the markets, as well as the sort of changing dynamics in the marketplace here, are there any of those packages that you would look at right now and say, you would rather keep this rather than continue to have them out there, either based on well results or bidder response or whatever it may be?

We have been looking and based on the responses we've gotten from external interest and to the degree that we've progressed our JVs, we have been thinking about which ones may not be as attractive right now in the marketplace, which ones may be better off next year or when certainty, with respect to LNG export, becomes a little bit more obvious. But we're not at a stage right now to take any of them off the market. We find that, often times, we get surprises. So we're going to continue to market them, and we'll wait and see.

And then I guess, just to follow up quickly on that. You talked about the U.S. passages and your intention to allow some of the assets to be bid on individually. How do you see the Cutbank Ridge asset? I mean, I think that, that one is fairly straightforward. How do you see that within the context of everything else you're trying to do here?

Look, Cutbank Ridge is one of those ones that has become very interesting for us because in the last year, we've been able to significantly reduce our cost structures on that play by introducing cyclical racks, and we've also been able to improve the recoveries. So our supply cost has gone down on that, and our value has gone, from our perspective, has gone up. And so it's one of those things that it might be better to wait a little while longer before we conclude a transaction on that one.

Your next question comes from the line of Matt Portillo from Tudor, Pickering, Holt. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just a few questions for me. On Q3 gas, could you give us an idea of potentially where you exited Q3, from a total gas volume, so that we would have an idea of where gross volumes are once all the shut-in came back on stream?

Yes. I think we exited around 3 Bcf per day. So, we've been bringing gas volumes back on since about the beginning of August, and we haven't invested as much in other dry natural gas programs this year. So we were having falling -- declining production going into the quarter as well. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Great, and then I know that you've brought on a few wells in the Mississippian, I was curious if you'd like to comment on kind of your initial thoughts there, and how you guys are looking at the play. And then just a final question for me, in terms of your results to date across all of the liquids-rich basins, are there any of the plays, so far, that you're more encouraged on and that you may potentially look to accelerate relative to some of the other liquids basins that you're in at the moment?

Sure. I'm going to have Eric Marsh first talk about the Mississippian. The Mississippian Lime play is, of course, one of our plays we have the least amount of internal information on, but we have a tremendous amount of external information, and then I'll follow it up with both Jeff Wojahn talking about some of the other plays in the U.S. and Mike McAllister in Canada.

Max, this is Eric Marsh. We've got 2 rigs running the Mississippian and we've brought on 3 wells kind of in Western Kansas, and right now we're just now starting to de-water them. So, we really don't know much about them, and the plan really is to get about 16 wells drilled over 400,000 acres and really evaluate it. So that's kind of where we're at now on the Mississippian.

Do you want to talk about Tuscaloosa as well and the Eaglebine?

Could. In the TMS, we have 2 rigs running. We have 2 wells completing, and let's see. We have one that's just about to come on. So we should have additional production on probably in the next couple of weeks. In the Eaglebine, we've had one rig running in the Eaglebine really drilling mostly in that Gresham area. It's going well. We're pleased with the results there. We have 2 additional wells that we'll be bringing on here this next week.

Yes, Jeff Wojahn. I could talk a little bit about the Rockies programs to kind of fill the slate. In the DJ, chasing the horizontal Niobrara, we have 2 rigs running right now, and planning to drill 25 gross wells this year. And the results there have been commercial, and we've been very satisfied with the results that we've had in that area, and we continue to be encouraged by what we've see. In the San Juan Basin, we continue to appraise the land that we have acquired in that area. We have 174,000 net acres, and that is pursuing [ph] the Gallup formation with horizontal wells. And there's a lot of vertical control in that area and because of that, we have a relatively lower risk profile than maybe some of the other plays in our portfolio. But it is going very well. We're still learning every day, and we've drilled 5 wells to date on that play.

This is Mike McAllister. With respect to Canada, in the Duvernay, we've rig released 7 wells and with a plan to drill 12. We have 2 rigs running right now in the Duvernay. And the reservoir has really come on as we've predicted with respect to liquids concentrations. Also in the Duvernay, we've had some really good results with respect to reducing costs. We've just had a record bit run on our latest well of 1,500 meters, all basically helping us get to a lot more confidence in the play. With respect to the other emerging play, if you will, with our Clearwater oil play, we have 13 wells drilled year-to-date. We plan on having a couple of those on here in November on stream, but the initial test results on a couple of our wells were very, very encouraging.

Matt, in addition, what I'd say is that our plan right now is to roll out a significant amount of additional operational information along with our budget in early February of 2013, and so that'll be a point where we give a major update on all of our plays. And we'll give a detailed spend profile for the next year, as well as an expectation for production and comments around commerciality and returns. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Great. And then just a last question on the hedging side. You guys got off, it looks like some pretty nice hedges during the quarter. Do you feel pretty comfortable with where the hedge book sits today or given kind of gas in the back end of next year above $4, is that something you may add additional hedges in at this point?

Well, historically, we tended to hedge up to 50% of the expected gas production in the upcoming year, and we usually have that done by the time we roll out our budget. So we'll be just watching the market and see if there's opportunities.

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

Yes, a couple of questions for me largely on spending. Randy, you mentioned the value of the joint ventures you're looking at right now greatly exceeds the targets you're looking to hit in terms of divestitures. With that and the hedges you've put in and strip pricing being above, what you -- the $3.50 you've planned on previously is -- I mean, does that imply that you don't need to get all the joint ventures and divestitures done to still spend the $4 billion to $5 billion you're planning for next year?

Yes, that would be true. I mean, we have seen nice movement in the forward curve, and we've locked some of that down with the hedges. We're continuing to work on and refine our capital spend as well for next year. But at this point in time, I'd say the guidance that we gave back at Investor Day looks to be pretty good with the exception of the incremental cash flow, and then time will tell on the JVs whether or not we need to do as many.

I see. And then what's the sort of spend profile look for next year? If you take the midpoint, it's sort of $4.5 billion, it's, what? $1.1 billion, $1.2 billion a quarter, Q2 to Q4 this year you're kind of spending in the $800 million range. Is that -- expect that sort of step up immediately in Q1 or is that sort of a steady ramp up throughout the year?

It will probably end up being a bit of a ramp up because, as I said, we're not going to spend or commit to spending of the money until we have the funds in the bank and absolutely secured. And so if any of the JVs -- if we haven't fulfilled all of our JVs by the time the spending commitments come around, we'll end up slowing it down. So at this point in time, I don't expect to have all of the JV money in the bank by the end of the year, all the requirement for next year. So I would expect it to be a ramp up.

Okay, great. And last one for me just going through the release today and I'm looking at the planned number of wells for the sort of emerging oil and liquids-rich plays and comparing that to prior numbers, some of them it looks like you've increased the number of planned wells this year and others, it's come down slightly. Is it fair to infer from that areas where you're having better than expected results and worse than expected results or are there other reasons that you'd be sort of shifting those plans around?

Yes, I'd say there generally are other reasons, and I can have Jeff talk a little bit about our changing plans in the TMS, for example.

Yes, Jeff Wojahn here, Mark. The TMS and the Eaglebine, one of the things we're very cognizant when we rolled out the program is that we didn't want to operationally out step our learnings. And in the TMS, we've had some challenges or we've identified a challenge around well lower [ph] stability. And so we took a timeout while we got our experts together from across the company to develop strategies rather than going ahead and just drilling money with old strategies that we thought would be of high risk. Likewise, in the Eaglebine as well, we went ahead with a one rig program because we thought that, that would be in line with our ability to learn from the information that we were gathering. So I think it's more of a function of prudence and discipline by the teams, on how they evaluate the opportunities and mostly that's how we feel [ph] about it.

And so far -- and the results we've had on the more recent TMS wells have proved that we have a good strategy.

Right, right. We have a number of drilling strategies, and we're sort of getting the early results on that. And so far, they corroborate the hypothesis that the teams have come forward relative to improving cost and decreasing drilling times. So we're making good progress. It's kind of slow and steady and we're hopefully trying not to outspend our learnings, and that's really what we want to do.

That's great. On the flip side of that, areas where you guys have increased the number of planned wells is that just freeing up where areas you have slowed down you've got that money available on the budget and reallocating that or just results exceeding expectations?

That is largely what has happened. Yes, it's been reallocated across the business.

Your next question comes from the line of Bob Brackett with Bernstein Research. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: I have some questions on liquids and then gas. On the liquids, you've got an exit rate of 40,000 a day for 2012. Looks like you’re around 30,000 now. What are the moving parts that gets you to 40,000? And then I'll follow up.

Okay, who's best to answer that. Jeff?

Jeff Wojahn here. One of the items is the midstream renegotiation, where we talked about some of the details around that deal or that negotiation is that it -- the deal does not reflect historical volumes, but rather it's a deal to incent future drilling in the Rockies. And so future volumes, we'll be able to basically be part of that renegotiation. We estimate that part of that volume growth from that transaction will be reflected in the fourth quarter, and we're thinking right now that it'll be somewhere in the 3,000 to 4,000 barrels a day growth in the Rockies related to that incentive that I talked to about future wells.

And then in Canada, Mike McAllister will answer.

Bob, yes. So as you would have seen the release, we've started up the Musreau plant or Pembina's start up their Musreau deep cut plant here in September, and they've got their turbo expander on now running. So we're up to additional liquids coming out of Musreau, about 6,300 barrels per day, as well as we've seen improvements in our liquids production in our Peace River Arch area as well. So both of those are growing into the end of the year. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: Great, and then on the gas side, you talked about the industry as a whole has too few gas rigs to keep supply growing. How many rigs would you guys need to keep 3 Bcf a day flat?

Actually, I haven't taken a deep look at that yet. Our plans are to be relatively flat year-over-year, but part of that is because we have that big kick from Deep Panuke. So we are, would otherwise be under drilling what we need. Probably something we can get back to you by the time we get to our -- in February.

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

In the operational update in the press release, you indicated a couple of things. The Duvernay condensate yields were very promising, that some of the wells in the Eaglebine are exceeding expectations and that the Tuscaloosa focus is on reducing drilling cost. Can you give us a more specific update and perhaps, in the Eaglebine, holistic update on the well results versus your expectations and the cost trends?

Okay, do you just want that on the Eaglebine?

I guess for the Duvernay, Eaglebine and Tuscaloosa. Illustrating some of the more general remarks that you made on your release and then in the Eaglebine, specifically, you talk about some of the wells, maybe something that's a little bit more holistic.

Okay, we'll start with Eric. Okay.

I think on the Eaglebine, Brian, I think the comment really is, is that like any place you drill, you have some that do better than others. And out of the wells we've done, we've had 3 or 4 of them that have been really good wells, and we'll give you an update on that probably in the fourth quarter. But overall, costs are in line; well performance is pretty much right online with our expectation, plus or minus; and then the area appears to be fairly honest as far as our drilling completion work. I think, in the TMS, I think it's all about the cost, it's all about working on our drilling cost and reducing the trouble times that Jeff just referred to.

Yes, maybe I can jump in as well, Brian. On TMS, one of the exciting things is that -- and we said this at Investor Day, and I'll maybe repeat it, a number of the wells that we drilled, some of the longer horizontals, were pretty good -- pretty close to our target type curves. And we have a target type curve for that area of around 730,000 barrels EUR. A couple of our wells appear to be, with reasonable extrapolation of future declines, right on target. So the TM -- and the other thing we talked about at Investor Day is we've also appraised the reservoir, our land base, pretty well. We have wells 25 miles apart and have similar production performance characteristics. So we're pretty confident about the resource potential of the TMS. And that it's a very, very large resource potential. Now, our focus is moving away from appraisal to sort of attack a target cost. And we're targeting to get our cost in that $13 million, $14 million, $15 million range. And I said this at Investor Day, we just drilled a long lateral 7,500-foot horizontal, 30-stage completion in the Haynesville that we brought on kind of mid-year this year. And those costs were in that range. So I have every confidence in our team's ability to replicate their performance that they've done in the Haynesville, because we're really talking about 13,000-foot depths with the same kind of challenges. So that's not to say that it's a slam dunk, that we can just take our Haynesville program and move it to the TMS. There is differences in the local geology, but we're really talking about costs not resource when it comes to TMS, which I feel very confident in.

All right. Mike, do you want to talk about Duvernay?

Yes, you bet you. So with respect to Duvernay, let's say, in going into the play, we had done extensive maturity mapping across the play area, really identifying the areas of highest liquids concentration. And our drilling results to date have really proven that out that what we predicted we see for liquids, we are seeing that. Where we're seeing anywhere between 45 to up to 300 barrels per million. So very, very encouraged by that, and similar to what Jeff said, as we've moved to the appraisal portion of the play, now we're moving in to okay, how do we become more cost efficient? And there's 2 examples. I mean, I'm talking about how do we run our bits longer in the hole, and we had a record bit run now of our latest well at 1,500 meters, as well as in terms of optimizing our completion techniques and really focusing on towards slick water fracs, which give us an opportunity to really drive our completion cost down. So moving -- everything is moving very positively in the right direction with respect to the Duvernay.

That's very helpful, appreciate that color. And then lastly, if we assume today's strip prices for oil and gas hold next year, what should we expect your gas rig count to do and what would that suggest for your gas production decline or growth year-on-year?

Okay. Sorry, you must have missed it in the last question. We weren't able to answer what our rig count is going to be, but our expectation right now is that we'll have a flat gas production going into 2013. And basically, a little bit underfunded at this point in time, meaning that we would be into a bit of a decline if it wasn't for Deep Panuke project coming on and making up somewhere in the range of 200 million to 300 million a day for the year.

So your outlook is that even though your decline would only be slight, the industry decline would be greater despite a similar rig count trend?

Sorry, I don't...

I think you made some comments earlier that you expect a more meaningful decline, overall, in terms of U.S. production should the rig count not improve, if your rig count is not improving, it sounds like you're saying your decline will only be modest?

Our decline would have been -- we would have been dropping off about 10% of production that's being offset by the Deep Panuke project coming on.

Your next question comes from the line of Robert Bellinski with Morningstar.

Just was wondering if you could provide an idea of supply cost for those volumes that you shut in or bringing back online. And then if you could talk to -- was there anything specifically that spurred you guys into, to start bringing those volumes back online versus maybe waiting a couple of months and seeing what winter demand looks like?

All right. Well, we shut the gas in largely when natural gas prices fell below $2.50, when the NYMEX fell below $2.50. And we said at the time that if we shut it in for the full year, we need about another $1 to make up for the present value of the loss in production. And when natural gas prices started moving up in August, I think prices went over about $3 in August, our plan had already been to make sure that we would have most of our natural gas production on before winter, particularly the Canadian gas, where there can be some difficulties if we would have waited to a time where we got into a hard freeze. So since the price moving had already gone up and the forward curve was projecting over $4 for -- in a range of $4 for 2013, we thought it prudent to bring those volumes back on.

Okay, that's helpful.

Supply cost was one of the filters, but it wasn't the absolute filter when we shut them in.

Got you. Okay, and then kind of a follow-up on the hedges that you just added. Are those structured as fixed price contracts or are they maybe collars or puts or something like that?

They're all swaps. So fixed-price contracts.

Got you, given your optimism, I mean, is there reason you didn't want to go with something with maybe a little bit more potential for upside?

That'll also expose you for more potential for downside. So given the optimism, we believe that natural gas prices will settle out in the $4 to $5 range over the next couple of years. We have considerable volume, which is exposed to that potential upside, and we typically always leave a volume exposed.

Okay. Great, and then just last one's kind of a shot in the dark here. Any additional news on Kitimat or anything on progress on finding an offtake partner?

Nothing we can really update you on. We always rely on Apache, our partner, to provide those updates.

Your next question comes from the line of John Herrlin with Societe Generale.

I was wondering with the JV packages, how much smaller are you making [indiscernible] intended to...

Really we're having some difficulty hearing you but are you saying how much small...

I'm sorry, Randy, I've got a cold. With the JV packages, how much smaller are they going to be than what you originally intended?

The only package that we are changing right now is splitting up the combined 3 property package in the U.S., The Eaglebine, Tuscaloosa, Mississippian package and allowing bids to be made separately on those. We are though, as well, considering the possibility of some of our mature acreage. If we could do a direct sale, we might create some designer packages that might fit the market. But we haven't ruled those out yet.

This brings to the end of our Q&A session for today's call. I'll turn the call back over to Mr. McRitchie for any closing remarks.

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

This concludes today's conference call. You may now disconnect.