Good day, ladies and gentlemen, and thank you for standing by. Welcome to the Encana Corporation's fourth quarter 2016 year-end 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. Members from the investment community will have the opportunity to ask questions For members of the media attending in a listen-only mode today, you may quote statements made by any 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 fourth quarter and year-end 2016 results conference call. This call is being webcast and the slides are available on our website at encana.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 annual report 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, reports its financial results in U.S. dollars. So references to dollars means U.S. dollars; and the reserves, resources and production information are after royalties unless otherwise noted. This morning, Doug Suttles, Encana's President and CEO, will provide the highlights of our fourth quarter results. Mike McAllister, our COO, will then provide some operational highlights. Sherri, our CFO, will then provide an overview of Encana's financial position and 2017 guidance. Reneé Zemljak, our Executive Vice President of Midstream, Marketing & Fundamentals will provide some highlights on Encana's risk management and market access strategies. We'll then open the call up for Q&As. I will now turn the call over to Doug Suttles.

Thanks, Brendan, and good morning, everyone, and thank you for joining us. 2016 marked a pivotal year for our company as we positioned ourselves to create value and return to growth in 2017. We dramatically lowered our cost, strengthened our balance sheet and launched a five-year plan to deliver leading cash flow growth and returns. We had a strong finish to 2016, producing more than 237,000 barrels oil equivalent per day in the fourth quarter from our core assets. This high-margin production made up almost 75% of our total fourth quarter production. This is up from less than 50% just two years ago. We reduced our cost by more than $600 million compared to 2015, and delivered strong cash flow of $302 million in the quarter. And our capital came in below the midpoint of guidance. We also saw a reserve replacement ratio of a 175% on a proved SEC basis. Through the course of 2016, we reduced our debt by about $1.1 billion, bringing our net debt at year-end to less than half of what it was at the end of 2014. And we have substantial liquidity of approximately $5.3 billion as we entered 2017. Our focus on innovation combined with the advantage of being in more than one basin is driving stronger well results and expanding our premium return inventory. We fully expect this trend to continue as we go through 2017. Activity across the North American exploration and production industry has picked up considerably over recent months. We have positioned ourselves well to manage the pressures this creates, both on cost and on performance. We largely completed our activity ramp in the fourth quarter of 2016. We have been actively managing the supply chain and we continue to use innovation and technology as a tool to offset inflation. Our 2017 plan will deliver substantial cash flow and margin growth. We will see our core asset production grow by at least 20% from the fourth quarter of 2016 to the fourth quarter of 2017, and we will grow our crude and condensate production by about 35%. We also have confidence that we can keep well costs flat through the use of technology, innovation, supply chain management, and driving execution performance. We expect 2017 capital spending to be between $1.6 billion and $1.8 billion. This capital program will be funded from cash flow and cash on hand. We have protected this cash flow with an active hedging program. We have 70% to 75% of our 2017 crude, condensate, and gas volumes hedged as well as an active basis hedging program. I will now turn the call over to the team, starting with Mike, to provide more on our 2016 performance and our 2017 plans.

Thanks, Doug. In 2016, we demonstrated that we can create tremendous value by focusing on innovation and technology to drive efficiency and rapidly transfer successful ideas across our portfolio. By focusing on completion design and stacked resource we have across our assets, we've expanded our already-large premium return inventory with more to come. Our drive for efficiency also generated our lowest operating cost, fastest drills, highest pump times and our most productive wells yet. We're also prepared for more active industry environment by ramping up to our 2017 activity levels before year-end. This greatly de-risked our ability to execute our 2017 program. In addition, our approach to innovation and supply chain management gives us a real advantage in offsetting service cost inflation. As I'll explain later, 60% to 70% of our capital program is either self-sourced or has service costs locked in. In addition, to all of this, 2016 was our safest year in our company's history. In the Permian, we've been focused on driving returns by making better wells at lower costs. I'm pleased to report, that our Q4 wells are continuing on that trend. Our latest completions design with over 30 days of production history are in Midland and Howard Counties. With our increased drawdown strategy, these wells are delivering IP30s in excess of 1,200 BOEs per day. On one of the Howard County wells, has been flat to slightly inclining at approximately 1,100 barrels of oil per day after 65 days of production. This flow was completed with 1,900 pounds of sand and 1,300 gallons per foot of lateral length. In the fourth quarter, we maintained our already-leading D&C cost at $5 million per well. We continue to capture additional operating efficiencies with spud to rig release times dropping below 10 days with our best being below…

Thanks, Mike. We saw strong cash flow growth improvement throughout 2016. This was driven by higher proportion of our production coming from our crude and condensate-rich assets. Significant cost reductions across the business also contributed to our cash flow growth. A disciplined focus on increasing efficiencies and improving operations reduced our cash costs over $600 million compared to 2015. For example, our initial guidance in operating costs, excluding long-term incentives was $4.70 to $5 per BOE. Our team executed on over 700 initiatives to reduce our operating costs and the actual result was $3.87 per BOE. During the year, we also took measured steps to strengthen our balance sheet. We finished the year in a strong financial position with access to significant liquidity. At year-end, we had $834 million in cash and our $4.5 billion credit facility was undrawn. Our 2016 capital program was very focused with 97% of our capital allocated to our high-return, high-margin core assets. With our results this morning, we also announced our year-end reserves and resources. Our reserve additions replaced 326% of full-year production on a National Instrument 51-101 2P reserves basis, and a 175% of full-year production on an SEC proved reserves basis. Please refer to our news release for further details. 2017 marks the first full year of our five-year plan to deliver leading cash flow growth, by continuing our discipline focused on growing production from our core assets. We expect to grow our 2017 corporate margin to over $10 per BOE. This represents a 55% improvement from our 2016 corporate margin. Our 2017 capital program is expected to range between $1.6 billion and $1.8 billion. This will be funded by cash flow as well as cash on hand. Our strong risk management program provides increased confidence in our cash flow and ability…

Thanks, Reneé. As you can see, we are well on track with our pivot to cash flow growth in the 5-year plan we laid out back in October. We have expanded our premium inventory, driven efficiencies into every corner of our business, delivered strong well results, strengthened our balance sheet, and are actively managing inflation pressures to grow margins and returns. Our 2017 plan delivers substantial cash flow and margin expansion, driven by the growth in our core assets and our increasing oil and condensate production. Our team is well prepared to execute this program efficiently. As we look out to 2018, the trends continue. We are set to dramatically grow cash flow driven by a further 30% margin growth at flat pricing, combined with over 30% production growth in our core assets. This sets us up to grow within cash flow from 2018 onwards. Thanks for listening to us so far and now, we'd be more than happy to take your questions.

Thank you. We will now begin the question-and-answer session and go to the first caller. Our first question comes from the line of Greg Pardy of RBC Capital Markets. Your line is now open.

Thanks, good morning. Couple of questions for you. The first one is just on the Permian. Do you plan to construct more of the super pads like the Davidson pad?

Yeah, Greg. Thanks for joining us this morning. As we're moving the thing forward, I think our basic development program here is to actually build pad facilities with the expectation we'll reoccupy these pads on a regular basis as we develop the stack. We're still trying to figure out the optimum size of these pads and I think our 14-well original pad was the largest in the Permian and now 33, I think we're by far and away the largest pad in the basin. And I think we've mentioned before, we ultimately see that one location probably having up to 60 wells or maybe even 64 wells. We do think this is a way to maximize capital efficiency and the balance here is just trying to optimize cost structure with facility spend.

Okay, perfect. And then the second question is just with respect to the Montney gas. About 0.5 B I think of net gas coming on, so I'm wondering if perhaps Reneé can dig in a little bit more in terms of where that gas is going to go and just to ensure that you've got firm pipeline transportation that will get everything to the market?

Yeah, that's right, Greg. I'll hand it over to Reneé. And I think just as a reminder, there is three gas plants, two of them come on in the fourth quarter of this year and the third one comes on in the first quarter of 2018, and that will get you to about just short of a 0.5 B net. But Reneé maybe comments around getting it out of the basin and into the market. Reneé E. Zemljak - Encana Corp.: Sure. Thanks, Doug. Yeah, Greg, so we have those plants coming on in Q4, they are going to be tied directly into the NGTL system. That's north of the James River location. We do have firm transportation aligned exactly with our development program. We're expecting that gas to flow into the NGTL system with access directly into the oil sands as well as access to eco net.

Perfect. Thanks very much.

Thanks, Greg.

Thank you. Our next question comes from the line of Josh Silverstein of Deutsche Bank. Your line is now open.

Thanks. Good morning, guys. I just wanted to touch on the supply chain that you guys were focusing on today. Can you touch a little bit on the logistics here? Is that something you guys are handling and maybe how it differs in Canada versus the U.S.? I imagine you use different sands, different frac curves. Just how you guys are managing all this?

Yeah. Mike will pick this up. But I think one of the things on we started doing this a while back is, is we – way back at end of 2013 when we reorganized ourselves, we created the central supply chain team, who actually tracks all the markets across North America and we build strategies on how to make sure we're getting best value and then we combine that with a real strong linkage to our operating teams who also use things like new ideas/technology innovation and that's what leads to like the testing of brown sand. But on sand specifically for us, we can manage it from the mine right to the well side. But, Mike, you might add a few comments about both Canada and the U.S.

Absolutely. What we do is we unbundle our total frac spend and with that – taken sand as a separate item. So with that, we then look at each of our plays, core plays, be it Eagle Ford, Montney, Duvernay and Permian, and then set a strategy in terms of sand supply to each of those and come up with the best cost of that supply for each of the play. So it varies from play by play, and we manage it right from the mine as Doug mentioned right through to – right to the lease.

Got it. Okay. And then, you ramped up the rig activity in the fourth quarter now at the 2017 levels. Do you see any shifts as you go throughout the course of the year? Does the Duvernay come down, the Montney starts to ramp up? And for a company your size in the Permian, you guys could certainly handle some more rigs there. Just any thought about how that shifts throughout the course of the year?

Yeah, Josh. The big change through the year is roughly by about the middle of the year we will have ramped our Duvernay program completely down. The rest of the programs are relatively flat until the fourth quarter where we have a bit of a tail. If you look at the shape of our capital program, the capital spend per quarter is pretty flat for the third – first three quarters and then tails off slightly in the fourth. We actually like that shape, it's one we've actually used the last two years, because it gives us a lot of flexibility around. If we see stronger performance, lower cost, stronger cash flow we can actually fill in that gap in the fourth quarter if we choose to we or not. So – but just to recap, the only big shift is, is pretty active in the Duvernay in the first half of the year, including we've just drilled three Montney wells on our Duvernay acreage. So even though they're kind of Duvernay, they are in the Montney horizon. And the rest of the programs are largely flattish through the year until there is some small tail off in the fourth quarter.

Thanks guys.

Thank you. Our next question comes from the line of Brian Singer of Goldman Sachs. Your line is now open. Brian Singer - Goldman Sachs & Co.: Thank you. Good morning.

Good morning, Brian. Brian Singer - Goldman Sachs & Co.: I just wanted to follow up a bit on Greg's question with regards to the Montney. If the growth that you're projecting in terms of the doubling of liquids production by the fourth quarter, is that all back-end loaded into the fourth quarter of the year, when some of these plants come on? Is the upstream – is the wells coming from backlog or is it the program that you're planning for this year? And then is there any movement at all in terms of any change to finding ways with TransCanada moving gas into the down market, down the road?

Yeah. Thanks, Brian. Yeah, the big jump in Montney liquids, which is mostly condensate is in the fourth quarter. We are having to ramp up the drilling program now. It's interesting to think about what drives that, it's actually access to water to make sure that we don't have a problem executing completions with dry summer. I mean, I hate to hang things on the weather here. So we have a bit of activity through the year and we'll be slowly feeding in liquids-rich production priority over drier gas production, but largely the Montney ramp happens in the fourth quarter. Just on the other side because when you look at our total profile, we actually see a steady growth through the Permian quarter over quarter right through the year. Just an interesting side. If you just look and I think Sherri mentioned this in her comments. If you look at our Montney production at the condensate-gas ratios, we're now producing at a $55 oil price with a small discount for condensate in Canada, which is actually, recently it's been trading pretty flat with TI. We actually generate a very strong return at a minimal gas price, which was why she made the comment about this is a condensate play now for us with associated gas. Moving onto the mainline into the conversations with TransCanada, the good news here is, is that conversations between the producers and TransCanada have been ongoing ever since the last open season attempt. I think a number of us, a lot of us believe this should happen, and I'm hopeful we'll get something done. But I can't tell you people have been very actively engaged in this conversation right through the holidays and up to today. Brian Singer - Goldman Sachs & Co.: Great. Thank you. And my follow-up is with regards to SG&A, you highlighted there were a number of one-offs here and Encana was in restructuring mode in 2016. I think there was a reference in the financials that there seems to only be a little bit left on the restructuring charges. So as we think about the trajectory for 2017, I think you talked about a $45 million run rate, is that what we should actually see, or are there any more material kind of one-offs left that we should we aware of?

No, that's what you should expect Brian. We had that 20% downsizing back in March, so that flowed through. A few minor items. And then also when we had forecasted that number originally, we had expected the Canadian dollar to be a bit weaker than it turned out. But your run rate that of $45 is a good one to use for 2017. Brian Singer - Goldman Sachs & Co.: Great. Thank you.

Thank you. Our next question comes from the line of Gabe Daoud of JPMorgan. Your line is now open.

Good morning, Doug. Good morning, everyone. Maybe just starting on the services and cost side, 60% to 70% locked in, what are you guys seeing on the other 30% to 40% in terms of percentage inflation? And what's kind of baked into guidance versus, I guess, what you're currently seeing today in the field across your areas?

Yeah. Gabe and just so you know that, we've seen attempts – it's a very interesting market, which you know things are changing. First of all, in some service lines we actually see costs going down this year versus going up. Now, clearly the headlines are really about pressure pumping in a couple of the hardest basins. I mean, the two most active basins in North America are the Permian and the Montney. And, of course, in the Montney, you have a number of operators – we're not one of those, but a number of operators who operate seasonally, which creates additional pressure, particularly this time of year. So pressure pumping, we've seen request up in – of increases up into the mid-30% range, that doesn't mean they're getting those price increases. It's the beginning of the negotiation, and in some cases, we've had to replace suppliers, because we couldn't agree to terms. And as Mike mentioned, in one example in the Permian, we locked in on 2016 rates for one frac spread with by creating some optionality and a guarantee of work for that spread in an optionality in the second one. So our team has been pretty creative about this. And then in another areas, Mike highlighted it, sand and water make up a big piece of the cost of these wells. We actually think our sand cost are dropping this year, because of things we've done over the past two years. And our water costs are also being managed because of this use of produced water, which can save us up to $1 a barrel. And if you think of a typical frac in the Permian using 300,000 barrels of water, that's a $300,000 savings. So it is quite variable by service line. The remaining 30% has got ups and downs and small bits and pieces in there, and some of it's field manage spend. But overall, in most of the product lines, the increases are – or the request anyway are small, pressure pumping is the one place where the expectations in new bids can be considerably higher than 2016 prices.

Thanks, Doug. That's helpful. Just going to the Permian maybe back to Josh's question earlier. Just curious how you guys think about adding incremental rig activity this year. You're already at 5 rigs, you feel pretty comfortable with the ramp through the year. But just, how should we think about, and how do you guys balance accelerating activity further this year?

Yeah. This is an important year for us, as we go from decline to growth. Sherri, I think mentioned. I call it the bounce our top-line production in the middle of the year goes from decline to growth this year, and then we have strong growth in our core assets of 20% or greater from 4Q to 4Q. And we're outspending cash flow; we've been very explicit about that going back to October. But as Reneé mentioned, we protected that with a very robust hedging program. So it really depends on what the market looks like. And the second thing I would remind you about is it may not be adding rigs, but it may be more wells. Our productivity per rig continues to go up. Mike talked about in the Permian that we've got wells now drilled in less than 9 days. So it's possible our well count will go up in the Permian without our rig count going up in the Permian, as we drive execution performance and productivity.

Got you. That's helpful. I'll let someone else on. Thanks, Doug.

Yeah.

Thank you. Our next question comes from the line of Jeffrey Campbell of Tuohy Brothers. Your line is now open.

Good morning.

Good morning.

I thought it was really interesting that you transferred your Eagle Ford completion approach to the Montney, bearing in mind that we're often told, of the bespoke nature of completions in the various plays. And I'm just wondering if you could tell us why this was different. Why you felt an Eagle Ford to Montney transplant was more likely to succeed?

Yeah. And I'll let Mike pick up the detail, because he obviously understands that much better than me. But I will tell you that it's a phrase I think that Sherri used in her piece, but we believe in deeply. One of the things about what we call the multi-basin advantage is, is not only do we see what, for instance, the supply markets look like in the various parts of the basins and you guys probably know. We've actually taken suppliers from one basin to another to actually help create the right competitive pricing and performance. But we also constantly look for technologies that we can move around in real-time. And in fact, we built it into our organization structure. We have what we call our functional chiefs, which are not in the line. They sit outside the line, very experienced experts with very small teams. But one of their sole jobs is actually to identify, get technologies tested, then rapidly move them across the company. And maybe Mike can pick up the specifics of what we've been doing in the Eagle Ford and seeing great results and how we've now moved it to the Montney.

You bet you. Thanks, Doug. Yeah, we have functional chiefs, drilling completions, operations and facilities functional chiefs, with small teams as Doug had mentioned. Our completions chief is responsible for making sure we understand technologies that are being applied in all of our core plays across the company. And what we are working on collectively and working on in the Eagle Ford was trying to get more improvements or more near wellbore complexity with respect to our fracs, and to basically get better drainage, more near wellbore. We also saw that we had the same challenge in the Montney in terms of our frac design. So we tightened the cluster spacing, down below 25 feet in the Eagle Ford, we went to thinner fluids, which helped us with respect to reducing the stress shadowing and saw the tremendous success which I talked about in the Eagle Ford piece and then took that at literally within 12 weeks, Joel Fox, our Completions Chief took that to the Montney team, and we basically halved our cluster spacing in the Montney and had 50% improvement in our well productivity. This is not unique to completions, it happens in drilling, it happens in facilities, and it happens in our field operations as well, so it's working very well and it's something we've been doing for actually quite a long time.

Yeah. I might add one other thing to Mike's comments and just another example. We've actually talked about in the past like we pioneered the use of multiple rigs on a single pad and actually multiple frac spreads on a single pad in our Duvernay operations and took it with two rigs and two frac spreads operating simultaneously. We took it to the Permian and doubled it and went to four. Some of you have seen the photographs of four rigs operating simultaneously on the same pad and we actually ran four frac spreads simultaneously. So moving this technology around is something we think that gives us real advantage, because we think the technology has not even begun to slow down yet. And then the second thing is, is we do have to make some modifications, so the perf cluster spacing we're using in the Montney is actually a bit wider than the Permian, but we also have considerable higher permeability in the Montney, which may mean we don't actually need to go quite as tight, but you should see this trend continue for us.

That was great color. I appreciate it. On my follow-up, I just wanted to ask about something that I didn't see discussed in any of the plans and that was with regard to the no-go decision for the San Juan Gallup. I just wanted to – if it's still in the thinking and if you could share maybe what the most important variables are that will ultimately inform that decision?

Yeah, no – thanks for bringing that up. We have in the plan this year, 6 wells to be drilled in our San Juan position. 4 wells will come online sort of summer time – early summer and then 2 more wells in the late part of the summer. And what we've done is, we've rebuilt our geologic model down there. While we've taken this two-year hiatus, we've actually assembled some large Federal units, which are now allowing us to drill in what we consider the optimal direction and also drill longer laterals. So really what we want to do with these 6 wells is confirm what we think the type curve is going to like here. And then, somewhere around the end of the year, we can actually decide, does this asset in our portfolio move into development mode. We're excited by it. We follow the trends in the area. Some of the best wells that we drilled were our last wells and we think these will be better. So we're really trying to verify with the drill bit are new type curves.

Okay. Great. Thank you. Appreciate it.

Thank you. And then our next question comes from the line of Jeoffrey Lambujon of Tudor, Pickering, Holt. Your line is now open. Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.: Thanks. Good morning. Just a few questions on the service cost side. Circling back to the comment regarding having 60% to 70% of the cost locked in, I just want to understand if there are any cost pass-throughs in relation to labor and other line items we should be aware of as well?

Yeah, Jeoff. No, we don't. We don't use those kind of structures here. As you know, the world is getting busier. And actually what we probably all need to remember, this isn't the first time it's happened. And at these inflection points, particularly when they happen rapidly, it takes a while for the industry to realign itself, but it always does. It always realigns itself. And what we were trying to do, and Mike mentioned this, is we identified this concern back in July of last year. And sat down and identified where we thought the most difficult pinch points be, and not just on cost and access to supply, but it does impact performance. We're already hearing companies who can't get services or they are delayed considerably or the service they're getting is lower performance, lower quality, within what they were getting before. So we saw this risk coming and went into action. I would also say that, Mike highlighted this, and I think this is really important and something we've talked a lot to our service providers about is, first of all, if well costs go up a lot, I hope everybody remembers a way back to the house. Because the price of oil doesn't have an eight on it, doesn't have a seven on it, it doesn't even have a six on it. It's got a five on it. And unfortunately, the second number is less than five. What we've done as an industry has driven considerable efficiency and made North America shales some of the most lowest cost, best opportunity in the world. And if we see large increases, I wouldn't expect capital to budgets to go up, I'd expect the activity to go down. And what that means is, what we've got to do as operators is work with the service providers to create better efficiency, so they can generate a good margin as well. And Mike highlighted pumping hours per day. In a pumping service company working for us who is averaging 20 hours a day can actually charge us less per stage than they can other people and still make a lot more money, because that frac spread in that crew will generate over the course of the year, a lot more revenue. And these are the companies we want to work with. We want to work with companies who want to drive execution performance and make sure North America shale stays on the low-end of the supply cost curve. Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.: Understood. I appreciate the detail there. And then last one for me on the sand price agreements that you've got, just wondering how much is covered today, and then by 2018, 2019, how can we think about contracted coverage, just given the acceleration that's implied by the multi-year growth outlook you guys have provided?

Yeah. A reasonable proportion has actually covered, because I think Mike mentioned this, we have a contract which we renegotiated in 2015, which provides tonnage all the way to 2020, it's already priced. And it covers a large, a reasonably large portion of our needs, but we can supplement that with other sources. So we don't actually see a lot of pressure for us between now and the end of the decade on same cost. Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.: Thank you.

Thank you. At this time we have completed the question-and-answer session. I will now turn the call back over to Mr. McCracken for closing remarks.

Thank you. This now concludes our call. Thank you everyone for joining us today.