Good day, ladies and gentlemen, and thank you for standing by. Welcome to Encana Corporation's First Quarter 2016 Results Conference Call. As a reminder, today's call is being recorded. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. For members of the media attending in listen-only mode today, you may quote statements made by an of the Encana representatives. However, members of the media who wish to quote others who are speaking on this call today, we advise you to contact those individuals directly to obtain their consent. Please be advised that this conference call may not be recorded or rebroadcast without the express consent of Encana Corporation. I would now like to turn the conference call over to Brendan McCracken, Vice President of Investor Relations. Please go ahead, Mr. McCracken.

Thank you, operator. Welcome, everyone, to our first quarter 2016 results conference call. This call is being webcast and the slides are available on our website at encanca.com. Before we get started, please take note of the advisory regarding forward-looking statements in the news release and at the end of our webcast slides. Further advisory information is contained in our most recent Annual Information Form and other disclosure documents filed on SEDAR and EDGAR. I also wish to highlight that Encana prepares its financial statements in accordance with U.S. GAAP and reports its financial results in U.S. dollars. So references to dollars means U.S. dollars, and the reserves, resources and production information are all after royalties unless otherwise noted. This morning, Doug Suttles, Encana's President and CEO, will provide the highlights of our first quarter results. Mike McAllister, our COO, will then provide some operational highlights. And Sherri Brillon, our CFO, will then provide an overview of Encana's financial position before we open up the call up for Q&As. I will now turn the call over to Doug Suttles. Douglas James Suttles - President, Chief Executive Officer & Director: Thanks, Brendan, and good morning, everyone. Thank you for joining us. We delivered a very strong operational performance during the quarter. We are achieving basin-leading well results in each of our core four plays, both in terms of cost and production performance. We are on track to meet or beat our 2016 cost savings target of $550 million. Operational innovation is the key driver of our 2016 program. Just one quarter into this year, our teams are already meeting or beating their 2016 drilling and completion cost targets. As Mike will illustrate later, Encana is drilling some of the most productive and the lowest-cost wells in each of our core four…

Thank you, sir. Our first question is from Greg Pardy with RBC Capital Markets. Please go ahead.

Yeah. Thanks, thanks. Good morning and thanks for all that. Doug, I think on your year-end call you'd indicated that you thought the big four production would be down about 10% or so year-over-year in the fourth quarter of 2016. Is that still your thinking? Douglas James Suttles - President, Chief Executive Officer & Director: Yeah, Greg. It – as we highlighted, things are pretty much exactly where we expect them to be. Probably the only disappointment in the quarter from our perspective was particularly gas pricing, and obviously AECO basis was pretty low as it responded to the warm winter. But production's on track. I think you probably heard Mike talk about, in two of the core four, we expect production to grow in the second quarter, in the Eagle Ford and the Permian, but a lot of this is just due to timing of activity. Probably the most obvious thing is this 14-well pad we've just completed in the Midland Basin, which I don't know if you've picked it up, we're pretty excited about this. Significant reduction, and it's a substantial real test of the latest thinking on how you develop the Midland Basin.

Okay. Perfect. The second thing is maybe just to go back to the D&C costs, cost reductions. I mean, highly impressive. If you were to split those between cost reductions and process improvements, what would the rough split be? Douglas James Suttles - President, Chief Executive Officer & Director: Yeah, it's a good question. I'll make a couple of comments and maybe ask Mike to add some as well. I think first, we continue to see cost reductions from service providers. It's a tough environment out there for absolutely everybody, and everyone, if you will, is doing their part to make sure that North America is competitive on a global stage, and I think you're seeing that in these results. But it's a combination. I mean, to think that we did a spud-to-TD of our pace-setter well in the Permian at under 10 days is incredible. That 14-well pad, I think we averaged around 13 days from spud to rig release – not spud to TD, but spud to rig release – which is down more than 50% from just a year and a half ago, so these numbers are incredible. But I think roughly, the proportion is still the majority, probably in the neighborhood of about two thirds, of the benefits are coming from execution performance. Mike, buddy, I don't know if you have anything you want to add there. Michael G. McAllister - Chief Operating Officer & Executive Vice President: Yeah. Yeah, definitely, Doug. The service costs played a part in the cost reductions, but our pad drilling philosophy and the procedures that we put in place really help, and helps on logistics and driving down costs. As an example, our sand distribution costs are spread – on that 14-well pad, were spread over four different frac spreads at the same time. Same with the water distribution costs. Really helps you drive your cost structure down. So I think a lot of the cost savings, two-thirds, as Doug said, are going to stick as we go through the cycle here.

Okay. Perfect. And then just the last one for me is, you touched on the Eagle Ford; how core is the Eagle Ford, if you had to rank the big four? Douglas James Suttles - President, Chief Executive Officer & Director: Boy, that feels like a tricky question, Greg. Clearly, the returns are – we've talked about this before – are very competitive. And I kind of mentioned this at the tail end, by the way, with these cost reductions, and if you just use something like a $50 oil price and a $3 gas price, we've like doubled the rate of return on the average well we're drilling at a low deck. So these are wells which were generally in the low 20s% to 30% return and have moved well up into the 40s% or better with this substantial cost reduction. We use this term production efficiency interchangeably with capital efficiency. It's basically how much volume we generate per dollar we spend, and we've improved that by about 25%. So the other way to think about it is the supply cost, and we've talked about supply cost in the mid-30s in most of the places we're investing today, and that number is coming down. The Eagle Ford is competitive with that. The one thing the Eagle Ford gives us is a tremendous amount of flexibility. The acreage is held. We can actually, and this year's program is largely what we think of as a drill-to-fill program. So we're not building new facilities; we're filling in where we have excess facility capacity to get better capital efficiency. But it's very competitive. It doesn't have the same scale as the Permian or the Montney, or the same growth potential that the Duvernay has. That's probably the most significant difference in – that it has for us in the portfolio.

Okay. Great. And the last one for me. You did mention that you'd potentially look at other options later in the year, which is fairly open-ended, but if we're going to read that into what kind of WTI price would be needed for you to start to think about expanding the program, is that how we should think about that comment? Or am I reading things that aren't there? Douglas James Suttles - President, Chief Executive Officer & Director: Yeah. I wouldn't over-read it Greg. I think that what we're really saying is, we've got a lot of flexibility. We have – we can ramp programs up and down quite quickly, as we've showed. I mean, our capital was higher in the first quarter largely because, you remember, we reset the capital program in the middle of the quarter, in mid-February, and brought that down, and we're now operating at that lower capital spend rate. But it just shows we can ramp these programs up our down quite quickly. I think Sherri outlined how we use our hedging program to protect cash flows, and as I mentioned, we're already making competitive returns. So this is a matter of confidence in the commodity price and how we manage the balance sheet. And the only thing I was trying to highlight there was, we have a lot of flexibility. And we'll continue to monitor the market conditions, but we put a lot of emphasis on maintaining a solid balance sheet through this part of the cycle. So all I was really trying to say is we've got a lot of choice here, as we think largely the supply-demand curve begins to come into balance as we head towards the end of the year.

Okay. Perfect. Thanks very much.

Thank you. Our next question is from Nick Lupick with AltaCorp Capital. Please go ahead.

Yeah. Thanks. Good morning, guys. Just a quick question for me on the DJ. Obviously, we've sold that asset and I just wondered if you could give us a bit of an update on that, on the timing, maybe just what we're waiting for, maybe due diligence or what have you. And also if there's any expectation that the proceeds will change going forward. Douglas James Suttles - President, Chief Executive Officer & Director: Yeah, Nick, thanks. No, the story on the DJ hasn't changed since December. We're – I think we mentioned briefly there that we're still on track, we believe, to close by the end of this quarter. And the proceeds haven't changed; the deal terms haven't shifted. And we keep working forward with Crestone, who is the purchaser, to get that closed by the end of the quarter, and I still think we're on track to achieve that.

Perfect. Thank you.

Thank you. Our next question is from Jeffrey Campbell with Tuohy Brothers. Please go ahead.

Good morning, and congratulations on the cost reductions. With that in mind, I was going to ask, with the evolving cost reduction, if you were to land towards the bottom end of the CapEx guidance, would you be more likely to take on another rig or put the money on the balance sheet? Douglas James Suttles - President, Chief Executive Officer & Director: Well, you know, it's a good question, and actually there's a little bit of complexity in it. I think we indicated in the call in February that our guidance said $900 million to $1 billion, and I think I said in the call I'd be surprised if I saw that as $1 billion. And you're seeing the performance our operating teams are delivering, and it does give us the flexibility. But a lot of it's going to be about second-order optimization: does it make sense to continue a program or keep a frac spread working a little longer than currently planned? But it is the sort of flexibility we have. And as Greg asked about earlier, all I'm really trying to highlight is we have those options within it, and we'll continue to watch the performance. Some of this performance is incredible. I mean, if you think about when we entered the Eagle Ford in the middle of 2014, wells cost $8 million, and in the first quarter, we drill wells for $3.5 million. I think that's performance that can go head-to-head with absolutely anybody in that play. And we're a year and a bit into the Permian, and I think our well costs are leading edge and our well performance is leading edge. And this isn't only Encana's assessment; these are independent groups are writing these stories. So it gives us that option, Jeff. It's around the edges, though, and we'll just, as we get farther into the year, we'll be able to see, does it make sense? But we're talking a few tens of millions of dollars; that isn't substantial.

Okay. That makes sense. Slide four shows that D&C costs that we've been discussing are normalized to a 7,500-foot lateral, but the type curve on the same slide shows data based on an 8,500-foot lateral. I was just wondering what's the average lateral length that ECA is targeting for 2016 in the Permian? Douglas James Suttles - President, Chief Executive Officer & Director: Yeah, it does vary, and Mike will fill in, but one of the reasons we stuck that out there is some people are using longer type curves or longer well lengths for their type curves, so we're trying to be apples-to-apples. But just as an example, that 14-well pad that Mike talked about, our average well length's a little over 8,500 feet. And by the way, I think if you look at the deck, there's some pretty cool photographs there. I don't know of anywhere in the world where anyone's put four modern 1,500-class drilling rigs on the same pad, and I'm pretty certain no one has ever put four frac spreads on the same pad and simultaneously completed 14 wells. We actually had – recently we had I think it was five stick pipe and three coil units simultaneously drilling out those 14 wells. And this is what's driving this performance. There are real savings generated by doing that, whether it's logistics or ancillary services, but I think this is what leading-edge operators are going to be doing. Michael G. McAllister - Chief Operating Officer & Executive Vice President: Yeah.

Thank you. Michael G. McAllister - Chief Operating Officer & Executive Vice President: I don't know if you wanted me to add any more, but I think we're looking between 8,500-foot and 9,000-foot, would be kind of what we're targeting for lateral lengths this year.

Okay; thanks. I appreciate that.

Thank you. Our next question is from Jeoffrey Lambujon with Tudor, Pickering, Holt. Please go ahead. Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.: Thank you, good morning. Just two questions on CapEx. First on allocation across the portfolio, I'm just thinking about the wide basin in Canada, again with little disclosure on your hedge protection there, which is understandable given your contribution to the overall Canadian gas production mix, and then keeping in mind a continued shift toward liquids-rich drilling, and also you mentioned Eagle Ford flexibility – are there other parts of the budget that are flexible as well, to where we could see incremental capital put to work in the U.S. where, again, you don't have that AECO basis issue and where you're seeing well costs improve, kind of to a greater degree versus targets for the year? Douglas James Suttles - President, Chief Executive Officer & Director: Yeah. Just a couple things on the flexibility, so the – if I start with the Montney in Canada, I mean this – even in today's low prices, you got to remember that we're – Mike's comment about growing liquids to 50,000 barrels a day over kind of the next two years. And those liquids are largely condensate. And as you know, condensate here in Western Canada sells very close to WTI pricing. So it's a quality product. And a lot of the return, even with low gas prices, comes from that. In the Cutbank Ridge portion of our Montney, which is on the – in B.C., that plan really hasn't changed in a couple of years and really won't change. The only thing that's happening is it's becoming more and more capital efficient. I mean, we're now drilling those wells for about $5 million, which…

Thank you. Our next question is from David Meats with Morningstar. Please go ahead.

Yeah. Thanks, guys. I just wanted to ask, you mentioned a few work force reductions last year and I think on this call as well, and I was just wondering how much that impacts your ability to grow in a better commodity price environment? Douglas James Suttles - President, Chief Executive Officer & Director: Yeah, David. Good – another good question. The – we actually put a lot of effort in this. So when we did our downsizing in March, one of the things we did is tried to create the capacity to grow in how we did that. So we did two things which are a little different. One is, we did a big redeployment program where we displaced contractors and some service providers with staff, particularly in the field. And there are two benefits to us from doing that. Number one is it allows us to hold onto this talent, because we would expect our capital budget to be higher in the future than it is this year. So these are a lot of our engineers and even geoscientists. The second thing is, clearly it'll help their development. They'll learn new skills. They'll be more valuable employees going forward. The second thing we actually did was introduced a sabbatical program, where people could take time off without pay and we'd have the ability to bring them back. And the worst case for them is if we didn't bring them back, they would get their severance at that point. We protected around 80 people in doing that, so that's about 4% of the work force. But in particular, it's particularly meaningful because a lot of these staff are tied to our capital activity. So we've tried to create some flexibility in the way we're managing the work force to do that. In addition, this focused portfolio concept we had, and the things Mike talked about with our pad development schemes, makes it a bit easier for us to grow activity without having to proportionally grow staffing.

Okay. That's really good color. And just one more from me. On the – you guys reported some, I guess, more impressive than expected well costs, particularly in the Permian, and it sounds like part of that is technical improvements with the things you were doing, 14-well pads and all that kind of stuff you were talking about. I was wondering how much of your acreage can physically be developed that way? Douglas James Suttles - President, Chief Executive Officer & Director: Yeah. Quite a bit of it, actually. And we haven't talked about a lot of the details, but as we do normally in every play, we continue to work to core it up, to make it more contiguous. So we've done small deals to add little pieces to it, and we've also done some swaps to continue to core it up, because I think if you've watched our history, we tend to like to drill big pads with long laterals. And quite a bit of the core of our acreage allows us to do that. Then the other thing, don't forget, this is stacked pay, and we haven't – even in our 14-well pad, we're only accessing three horizons on that pad.

So it sounds like the contiguous nature of the acreage, that's the main driver, more so than anything geological? Douglas James Suttles - President, Chief Executive Officer & Director: Well, the acreage is in the core of the play, which is the stacked pay component. So if you look at what we're doing this year, we're focusing a lot of our work in Martin County and Lower Spraberry. We're actually drilling some wells there right now, which you'll see results from. And then as you go south to Midland County, it's largely been in the Wolfcamp, but we still have a lot of other zones. So it's a combination of the way the acreage sits, where it sits, the stacked pay piece, and then this continual effort to core it up. I should say, there's one other thing which I don't think we even highlighted on the call yet, but we further reduced the requirement for vertical drilling in our Permian position by another 12 wells through the first quarter. So we've massively reduced this program by working with the mineral owners in minimizing the amount of capital we have to put to that program. It's been a great effort by the team.

All right. Thanks a lot, I appreciate it.

Thank you. At this time, we have completed the question-and-answer session. I will turn the call back to Mr. McCracken.

As a reminder, Encana's Annual Meeting of Shareholders will be held this morning at 10:00 a.m. Mountain Time at the BMO Center in Calgary. A live audio webcast of the meeting as well as presentation slides will be available on our website. Thank you, ladies and gentlemen. Our call is now complete.

Thank you. The conference has now ended. Please disconnect your lines at this time, and we thank you for your participation.