Good day, ladies and gentlemen, and thank you for standing by. Welcome to Encana Corporation's First Quarter 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 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 Corey Code, Vice President of Investor Relations. Please go ahead, Mr. Code.

Thank you, operator, and welcome, everyone, to our first quarter 2018 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 Reports and other disclosure documents filed on SEDAR and EDGAR. Please note 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 after royalties, unless otherwise noted. This morning, Doug Suttles, Encana's President and CEO, will open the call. Mike McAllister, our COO, will then describe our operational results; Sherri Brillon, our CFO, will highlight our financial performance. And then Reneé Zemljak, our EVP of Midstream, Marketing & Fundamentals, will reinforce our commercial mindset and our approach to marketing and risk. We will then open the call up for Q&As. I'll now turn the call over to Doug Suttles.

Thanks, Corey, and good morning, everyone. Thank you for joining us. Q1 was another quarter of strong execution. We are right on track to achieve our objective of growing overall production by more than 30% for 2018, while spending within cash flow. This puts us on a trajectory to deliver core asset production in the fourth quarter between 400,000 and 425,000 barrels a day. This is remarkable to be talking about core production exceeding 400,000 barrels per day when we were producing less than 240,000 barrels a day only one year ago. Our quarter was critical in keeping us on pace to deliver the growing cash flow and volumes for 2018 and beyond. Drilling activity across the portfolio was significant in the quarter. We continued efficient cube development operations in the Permian with a backdrop of increased industry activity, while continuing to offset supply chain pressures. In the Montney, we continued an active drilling program with almost double last year's first quarter activity as we build liquids volumes into facility capacity. We ramped up drilling in both the Eagle Ford and Duvernay to deliver additional cash flow as those assets saw limited activity in the latter part of last year. Our cash flow continues to grow through to a combination of increased liquids mix and cost control. This means that higher commodity prices translate into higher margin and returns. Our cube development approach continues to show tremendous results when combined with advances in completion design and operational efficiencies. We are seeing excellent cube results in the Montney with recent cubes averaging 300 barrels per day of condensate per well. Our Permian cubes also continue to demonstrate strong results. Mike will show you some of our results in Midland and Martin counties and how productivity continues to progress over time. Importantly,…

Thanks, Doug. We've had a great start to 2018 carrying our momentum coming out of Q4. Our plan is well on track to deliver 30% production growth within cash flow. Our margin will continue to expand with further liquids growth in the Montney and strong operating performance. We remain focused on operating efficiently to ensure that price improvements translate directly to our margin. We have ramped up our activity across the portfolio and our teams continue to innovate to deliver even more value from the cube. In the Permian, our plan will deliver 30% annualized growth and 10% growth from Q4 2017 to Q4 2018. We expect growth in the Permian to be weighted to the back half of the year. In Q2, we're anticipating modest growth because of offset frac mitigation. In the first quarter, our strong operational performance fully offset production declines and we successfully mitigated weather-related interruptions. We remain focused on executing efficiently and at scale. Concurrent operations like utilizing four service rigs at the same time keep cycle times short and costs low by allowing us to share services on location. Our cube development approach and high intensity completions continue to deliver strong well results and value from our stacked pay reservoirs. Our cube approach delivers continued operational efficiencies beyond drilling and completions. Our centralized approach allows us to share facilities and water infrastructure to streamline operations. This has reduced our horizontal LOE to $2.50 per BOE in the first quarter. Our supply chain management strategy continues to differentiate us as a superior Permian operator. We are well-positioned to offset service cost inflation through sourcing efficiencies. Our approach to decoupling supply chain and self-sourcing our commodities gave us a significant advantage this quarter. We utilized 40% local sand in Q1 and are on track to be…

Thanks, Mike. Q1 was another strong quarter of financial performance with net earnings up from last quarter, and with operating earnings and cash flow at higher run rates than last year. Our plan for 2018 is on track with cash flow expected to balance with capital investment over the year. Higher activity levels in the first half will see a higher proportion of CapEx spending with cash flow growing significantly in the second half of 2018. Cash flow margin came in strong at $13.70 per BOE and we're confident in our full year target of $14 per BOE. Our operating margin continues to grow quarter-after-quarter. This measure has grown consistently through the execution of our plan, and we're well-positioned to capture upside to higher prices in 2019 and beyond. Our Q1 price realization show the benefits of our market diversification and we're well-positioned to manage the volatility in AECO and Midland markets. In addition to strong price realization, our steady improvement in netbacks highlight the benefit of managing costs to fully capture price upside. In March, we followed through with our commitment to return capital to shareholders. We commenced our share buyback with an outlay of $111 million, reducing shares outstanding by 10 million or about 1%. This strengthens our long-term per share growth rate. We expect to continue with our buyback through the year as we recognize an opportunity to grow per share financial results in a meaningful way on a low risk basis for our shareholders. We have renewed our revolving credit facilities now fully committed to July 2022. Our strong balance sheet and capital discipline have allowed us to continue to have only one financial covenant in our facilities. This covenant, based on a debt to adjusted capitalization threshold of 60%, ensures Encana can be resilient through…

Thanks, Reneé. We are well-positioned to execute another year of strong growth for Encana as we prepare to cross the 400,000 BOE per day milestone later this year and deliver free cash flow next year. We have an exciting five-year plan that delivers compound annual growth and cash flow of 25% as well as free cash flow of about $3 billion at what now looks to be relatively conservative prices. We are firmly on track to deliver our 2018 guidance. Our focus on generating quality corporate returns is driving continued improvement in the underlying performance of our business. We are boosting well productivity and leading the industry in extracting maximum value from our assets. We are fully offsetting inflation and ensuring that the improvement in commodity prices flows through to our margins and returns. We are managing risk and optimizing the prices we realize for our products. We are exercising capital discipline, delivering 30% annual production growth within cash flow, and we will continue to return capital to shareholders through our share buyback program. Thank you for listening to us so far. And we'd now be happy to take your questions.

We'll now begin the question-and-answer session and go to the first caller. Your first question comes from Gabe Daoud from JPMorgan. Your line is open.

Hey. Good morning, Doug. Good morning, everyone. And certainly appreciate all the prepared remarks, but maybe can you just talk a little bit about the CapEx and production trajectory throughout the rest of the year, just to get us a little bit more comfortable with the ramp and the exit into 2019? For instance, I guess, the activity levels that you guys exited at on 1Q that should largely be held constant throughout the year and so CapEx perhaps, I guess, moves lower throughout the year? Can you just – a little more thought on that?

Yeah, Gabe. Thanks for the question. We tried to highlight some of this during the call. But essentially in the second half of last year and particularly in the Duvernay and the Eagle Ford, we ramped down activity and we restarted and ramped up that activity here in the first quarter. And what you'll see is then we see decline coming off the peak in 4Q and we'll actually see production build in the second half of the year in those two assets. If I kind of go asset-by-asset, we've ramped up to three rigs in the Eagle Ford today. That will actually ramp down a little bit as we go through the year. We've currently got four rigs running in the Duvernay at the moment but that will also ramp down as we go through the year. The Permian will be relatively flat averaging between four and five rigs, similar to last year. And, as Mike said, we started the year in in the Montney at 13 rigs. We're currently at 10 and a lot of that is as we build capacity to fill these new liquids hubs. So – and I think Sherri highlighted this. We have a bit more front-end first half capital than second half and we have a – a lot of our production growth shows up in the second half of this year and particularly from the Eagle Ford to Duvernay and the Montney.

Thank you, Doug. And then in the Permian in 1Q, was there any infrastructure spend in that capital number of about $240 million for the quarter?

Gabe, very little. In fact, one of the things that we're really proud of is Mike mentioned our $2.50 per BOE operating cost on our horizontal wells. I think that's right there with the very best in the basin and we did it without spending hundreds of millions of dollars each year on infrastructure. Essentially, I think, we've been building our latest two water resource hubs. But, I think, as we've talked before, those cost in the neighborhood of $3 million, so it's quite small. The infrastructure spending is very small.

Great. Thanks, Doug. And then just last one from me, just a little sneak in on Montney question. At Tower, on the completion side, could you just talk a little bit about how that's different or how that's changed relative to the 3Q and 4Q Tower cubes that you guys put on? And then also at the Tower cubes, is there any well-bores in the Lower Montney at all? Thanks, guys.

Yeah. I'll let Mike pick this one up. I mean, fundamentally, what we've been doing right across the portfolio is advancing these high intensity completions which generally is driven by tight cluster spacing. But, Mike, why don't you pick that up if you would?

Yeah. You bet you. Yeah. We've increased our intensity of completions in Tower. We've got up to move from – to almost 2,000 pounds per foot on certain wells and down to 10-foot cluster spacing as well in the rich part of the zone. And yeah, we have tested the section at the lower portion of the Montney in Tower as well.

Thanks, Mike.

All right. Thanks a lot, everyone.

Next question comes from Benny Wong with Morgan Stanley. Your line is open. Benny Wong - Morgan Stanley & Co. LLC: Hi. Good morning. Just wanted to touch on the buyback. It seemed like came in a much higher pace than we were expecting. Just wondering if you can speak to the strategy around that. Was it just the stock looked particularly compelling at a certain level or was cash flow just much stronger with oil prices and how're you thinking about the potential pace of the remaining authorization?

Yeah. Benny, if you think about this. When you actually look at the number of days you can actually be in the market buying the stock, it's much more limited than you realize because of blackout periods and other things. So, you can't ratably do this sort of month-to-month. We fully expect based on what we see as current conditions to execute the full program. And that's like, for instance, we've been out of the market now essentially the entire month of April, because of the blackout period. So, it's not really a surprise to us. We're not trying to be overly complex here in how we manage this program trying to get smarter than the market. That's what you guys do, not us. But I would expect us to do. It really wouldn't have surprised us and I'd expect by the end of the year if conditions say the same that we'll have fully executed the program. Benny Wong - Morgan Stanley & Co. LLC: Great. I appreciate the color on that. And just one example on Permian differentials and would love to get your thoughts on this as well, Reneé. We've seen differentials really widen now what seems to be a lacking of pipeline until the back half of 2019. I know you guys are well-mitigated from this, but once you get your outlook here and how wide you think these differentials can go and how the industry can get the production to market until those price come in?

Benny, Reneé can fill in lots of information here. But what's interesting is, if you look at this both in Midland basis and in Waha, we believe we could see this coming for quite some time, and bridge similar to what we did at AECO which is trying to understand what's going to happen with regional growth and how that fits with our export capacity, then how do you position yourself both physically and financially. Because, in some ways, we're right back to where we were in 2014, but, Reneé, maybe you'll fill in some thoughts. I'm sure Benny would like to know exactly what diffs are going to get to. Reneé E. Zemljak - Encana Corp.: Well, thanks, Benny. I don't know that I can predict exactly where the differentials are going to go to. We are concerned that they will continue to widen. The basin most likely is going to need a combination of trucking and rail to actually get the barrels to market. As I'm sure that you're aware, there are several pipelines that are expected to come into service in 2019. In fact, the most recent one that was announced that went to FID was the Gray Oak Phillips 66 Pipeline. So we are expecting differentials to continue to widen from here and it will go to trucking and rail economics. It could go out as wide as maybe as $14, $15. We're not sure but we expect to continue to see pressure on those differentials until the end of 2019. Longer-term, no, I would like to reiterate though that we believe the infrastructure for the most part will keep pace with production growth. So we'll see what 2020 brings us. Benny Wong - Morgan Stanley & Co. LLC: Great. Appreciate the color, guys.

Next question comes from Brian Singer with Goldman Sachs Your line is open. Brian Singer - Goldman Sachs & Co. LLC: Thank you. Good morning.

Morning, Brian. Brian Singer - Goldman Sachs & Co. LLC: Wanted to follow-up a bit on the Montney with regards to the production trajectory. You further accelerated the number of wells drilled into 40 in the quarter. Can you just talk a little bit more on the timing of that ramp-up and to what the magnitude of higher condensate yields and the impact that that has on the ability to process that condensate and get those well to sales?

Yeah, Brian. I mean Mike will fill in a lot of the information here. But we do expect to see pretty significant liquids growth quarter-over-quarter from Q2 to Q1. We do have – Mike mentioned this. We do have a plant turnaround in one of our gas plants in the quarter which is going to impact volumes a bit. That's been planned. That's part of the plan. And then, of course, in the second half of the year, we have the two liquid subs coming on; one in Cutbank Ridge in British Columbia; and the other one at Pipestone in Alberta. And, of course, what we're doing is starting to drill wells to be able to access that but maybe, Mike, you can add some more color.

Yeah. Here, come this May 22, we're scheduled to come down in our Sexsmith plant for a turnaround, which is going to last about 18 days. So that impacts Q2, as I mentioned, about 5,000 BOE per day. With respect to the liquids growth, I mean, we're really confident. We're seeing some great well results that support our ability to grow our production, Brian, between 55,000 to 65,000 barrels a day here coming into Q4. That's supported with two liquids hubs which really are the front-end liquids separation of our gas plants, one in the North Central Liquids Hub that will feed our Tower plant and take the liquids out going into our Sunrise gas plant and then in Pipestone. So, generally speaking, we'll see good liquids growth starting in Q2, but it will ramp up as we approach Q4. Brian Singer - Goldman Sachs & Co. LLC: Great. Thanks. And my follow-up is with regards to the Permian. I think you mentioned that you'd be moving towards 100% sourcing from local sand. Can you just talk about the logistical risks if any that you see in moving that sand to where you need it today?

Yeah, Brian. Just one thing I want to mention. Because some of the mindset that I think that Reneé really focused on in her talk we tried to do right across the business which is actually looking for both risk and opportunity. And we've talked about this in the past, particularly as we exited 2016 into 2017 where we saw industry picking up and said what are the risks that presents, how do we get in front of it and what opportunities do we have to create savings to offset some of that pressure. And, of course, one of the things we've done is we fairly quickly moved to local sand and have been support of that, managed that logistics ourselves. I'll just give you another interesting way we think about this. We've been leading a group of operators in the basin to figure out how we can get trucking more productive. And this is an example of kind of how we think. What we've said is the constraint really isn't on trucks. It's on truck drivers. So how do we get every truck to haul more sand? And we've been working with the legislature and the regulators to do things like can we haul, can we pull double trailers, can we add an axle to the trailers and increase the load capacity of the trucks? And I just emphasize this because this isn't the largest companies in the world we think about this. This is us. We get in front of these issues. We think about them. And then, in many cases, it requires collaboration with the other operators to do that. But, more specifically, Mike can tell you about we did feel some pressure in the first quarter as some of the local mines are a bit late coming on.

Yeah, yeah. Thanks, Doug. Yeah. Brian, basically, local sand that we sourced here in Q1 was about 40% of our requirements. The remainder came in on rail and using our terminals. The expectation is we'll get to 100% local sand here by the end of the year. Savings on local sand versus railing it in is about $0.02 per pound going from $0.06 down to $0.04 per pound. The issues were with the two sand mines that was in their assembly line related to some dryers which have been repaired. And so they're ramping up now to increase our local sand supply going forward. With respect to transportation, as Doug mentioned, the constraint is on truck drivers, not necessarily on trucks. And we went to the sandbox system and it's allowing us to move our sand basically on flatbeds, which is a lot more accessible. So that's also given us an advantage with respect to logistics and moving the sand to our well sites.

Yeah. Brian, I think, the last thing I'd just add to Mike's comments is one of the advantages we find of self-sourcing here is we're directly connected to a logistics chain, so we can coordinate that with our activities, where when others are relying on maybe the service provider to manage that. In many cases, they have no line of sight to constraints in the system and how that might impact their plans and their schedules. But because we manage that logistics chain ourselves, we can then link any disruptions there with our activity and not be surprised. So that's another advantage of the self-sourcing model. Brian Singer - Goldman Sachs & Co. LLC: Thank you very much.

Next question comes from Nick Lupick with AltaCorp Capital. Your line is open.

Thanks. Good morning, guys. Just a follow-up on Brian's question in the Montney. I just wanted to have a quick conversation about the condensate production that you're getting from the Tower cubes. Obviously there's a fairly sizable variance from cube to cube as you said during the call. Not all of them are in the same resource window. So I just wanted to talk to you guys about kind of the back half of the year, how many cubes you expect to bring on, which resource windows you think those will come on in? And I guess what I'm trying to get at is how much of that Q4 production growth is coming from Pipestone versus the cube developments in Tower?

Yeah. Nick, I don't think we could probably – we don't have the information right at hand for the call here to kind of go through a lot of detail on this, but Corey and the team can follow-up afterwards. If you look at the shape of it, the Pipestone piece is a modest proportion of it. It's not – the bigger chunk is actually in Cutbank, just because of the size. The slight difference there, as you know, in Pipestone, we effectively own 100%, whereas, in Cutbank Ridge, we have a partner there, Mitsubishi, and we own 60% and they own 40%. But the majority of the volume is coming out of what we call the North Central Liquids Hub and the Cutbank Ridge and then the remainder is Pipestone but it's probably easiest if we just follow up after the call with you.

Fair enough. Thank you.

Next question comes from Bob Brackett with Bernstein. Your line is open. Robert Alan Brackett - Sanford C. Bernstein & Co. LLC: Yeah. Could I follow up on the Permian market diversification? Can you talk about just your philosophy for 2020 and beyond?

Yeah, Bob. Great question and Reneé kind of highlighted this. She kind of started that with AECO. And we actually think that using a combination of physical transport combined with what we call firm in-basin sales to people with transport and then using the derivatives market for the remainder of the risk is the right balance. And the reason for that is if market conditions change, let's say, oil prices fell dramatically, you don't want to be long physical transport, because if you're long probably everyone else is long and it just becomes a drain on your business. Yet, at the same time, you can – we actually believe you can normally see – it's a lot easier to see these risks and we think manage these risks than it is the commodities themselves. We think you can actually – if you study it hard enough and we have – one of our four pillars is the midstream marketing fundamentals pillar where we spend a lot of time watching what's happening in the basins we operate in, not only from operators and what they're doing with capital and performance, but what's happening with the infrastructure. Then mix this combination of physical transport, market diversification and financial derivatives to take out short-term risk. Short-term can be a year or two. If it's decade long, that's where the multi-basin portfolio comes in where we'd actually just rotate capital out of the play into a better position, more advantaged play. Robert Alan Brackett - Sanford C. Bernstein & Co. LLC: Got you. And a follow-up on the Permian LOE being down at that $2.50 BOE. Can you talk about what artificial lift technology you're using or give some sort of insight into how you're keeping that number so low?

Yeah, Bob. Basically, when we – 86% of our production to be more exact – probably more exact than I should be, is actually related to horizontal wells. So, that $2.50 per BOE is our horizontal well LOE. And, generally, we progress through our artificial lift. Typically, we want to get the water off those wells as quickly as we can. So, we start off with the ESPs, transitioning to gas lift, and then finally to rod pump over a course of time of that well's life. So, ESP, gas lift, and then finally rod pump is the progression. Robert Alan Brackett - Sanford C. Bernstein & Co. LLC: Okay. Great.

And, Bob, one thing that helps here too, Mike mentioned it in his part of the call there is we've been very aggressive on using recycled produced water in our completions, in our development program and that saves us about $0.80 a barrel on disposal cost. So, not only do we have secure supply, not only are we making sure we're not competing with other users, it's also a lot cheaper than source water for frac jobs, but it also cuts our operating cost. And we see that percentage of produced water continuing to grow over time. We've had some pads as high as 80%. We've pumped entire stages that at 100% produced water now. And Mike already mentioned that we see a substantial growth year-over-year in the percentage of produced water and it does contribute to our savings. Robert Alan Brackett - Sanford C. Bernstein & Co. LLC: And that $0.80 per barrel, that's net of the cleanup cost of the produced water, the treatment cost?

Yeah. One of the things, Bob, we found, we started working on this a few years ago, is that we don't have to clean it up very much. The only thing we really have to get out of the produced water is the oil. So obviously it comes from our tank batteries and goes to our disposal facility. Then it runs to these water resource hubs which fundamentally just use three tanks in a Weir-type system to make sure we don't have any oil, but the operating cost of that is very cheap. This is the cool thing about our water resource hubs. They store 1.5 million barrels of water. It's in lined earth in pit with a section for produced water and a section for source water. And it also means we can do large multi-well pads because we pre-store the water before we start the completions. And I think we've talked about this. We can build one of these in 90 days and they only cost $3 million. That's why I think on the earlier question about infrastructure spend, our infrastructure spend is very low and our operating costs are very low. Robert Alan Brackett - Sanford C. Bernstein & Co. LLC: Thank you.

You have a question from Jeffrey Campbell with Tuohy Brothers. Your line is open.

Hi. I was wondering if you could talk about the extent to which waterborne exports are parts of your overall Permian and Eagle Ford sales plans.

Yeah. Reneé can pick this up, but we essentially can sell crude both in Houston and effectively so the recent deal we've struck out of Corpus and access Brent pricing if we choose to. Reneé E. Zemljak - Encana Corp.: Yeah. So our sales portfolio does include a combination of locations. So like Doug said we can go to Houston. We can go to Corpus. We do have access to Brent if the spreads actually makes sense. And with the volumes that we have most recently delivered into Houston off of the AECO pipeline, we have entered into sales transactions that were Brent related. They were Brent netback. So as we go into the future, we do foresee that we'll have a combination of Brent netback, Corpus netbacks and Houston netbacks to get back to our Permian pricing.

Okay. Great. Thanks for the color. I noted the pretty active Austin Chalk program with interest. I just wanted to ask a couple questions. One, are these all going to tend to be high oil cut wells like the one that you reported in the press release? And second, do you see these primarily as standalone wells or can they be incorporated into Eagle Ford beds?

Yeah. The oil cut will be consistent drilling. Basically some wells are offset to existing wells and really pleased, as I mentioned, with the results that we're seeing. And yeah, we incorporate these into basically the Eagle Ford cube with Eagle Ford wells and Austin Chalk both producing into the same infrastructure.

Yeah. Jeff, the concept we've had here we've stepped into this at a modest pace. I think we're up to about 20 Austin Chalk wells that we've drilled. And one of the things we did is it's a more complex play than the Eagle Ford. Many people know it's got a long and colorful history. And because it overlies our Eagle Ford, the land is already held by Eagle Ford production and where we're drilling the wells is accessing facilities that were built for the Eagle Ford development. And that's also impacted where and the pace of how we develop because we have wanted not to have to build new additional surface facilities. And those two things together have largely driven the pace. And I think Mike highlighted earlier in the call that the good news is we've had really consistent results. We haven't had a bad well but it is technically complex. It isn't as aerially continuous and contiguous as the Eagle Ford. So, I think, it's important for those who have the acreage, but it's clearly not going to have the same scale as the Eagle Ford had.

I'd say based on history having no bad Austin Chalk wells is pretty much a record. So, that's pretty great. If I could sneak one last quick one in. Slide 47 said that Encana will design, construct and initially operate the Keyera Pipestone facilities. Can you add some color on how or why you would cease to be the operator of those facilities?

Well, we did this in what was originally the Veresen-KKR deal, now Pembina. It's one of the things that the third-party midstream typically wants is the option to become the operator in that and that may obviously tie in with their future plans in the area. What it allows us to do? It creates a neat piece of linkage because if we can drive efficiency into the construction and the capital of these plants, we both benefit from that, particularly with the contract structure we have. And then, by us operating it early on, we establish the baseline for the cost of these plants which also creates a strong linkage in the future. And time will tell whether they decide to exercise that option or not, but it's something that was important to them and as long as we could set that baseline we were happy to accommodate that.

Okay. Great. Thank you. I appreciate it.

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

Thank you for joining us on our call this morning. This now concludes our call.