Good day, ladies and gentlemen, and thank you for standing by. Welcome to Encana Corporation's first quarter 2019 results conference call. As a reminder, today's call is being recorded. [Operator Instructions]. 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 Steve Campbell, Senior Vice President of Investor Relations. Please go ahead, Mr. Campbell.

Thank you, Operator. And welcome everyone to our first quarter 2019 conference call. This call is being webcast, and the slides are available on our website at encana.com. Before we get started this morning, please take note of the advisory regarding forward-looking statements in our 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 and reports its financial results in U.S. dollars. So any references to dollars means U.S. dollars, and the reserves, resources and production information are after royalties, unless otherwise noted by us. Following our remarks today, we will be available to take your specific questions. As a reminder please limit your time to one question and one follow up. This simply allows us to get to more of your questions this morning. I will now turn the call over to our President and CEO, Doug Suttles.

Good morning everyone. Thanks Steve. And thanks for joining us today for our first quarter 2019 conference call. I am joined today by other members of the executive team. As you know our long-time CFO and friend, Sherri Brillon is retiring after 33 years with Encana. She will be providing our financial update one last time but kindly offered to let Corey answer all of your difficult questions. Sherri has been a highly valued member of our team for quite some time and a great resource for me and the Board. On behalf of all of us I would like to thank her for her very many contributions to Encana. Let's get started. A lot of great things have happened since we last updated you in February and we are off to a very strong start in 2019. By now, I hope you've had a chance to read through our news release, our supplemental filing on the quarter and the detailed slides we provided on our website. We will reference these slides during our prepared remarks this morning. The quarter was complex so we will do our best to help with that. And of course Steve and the team will be available afterwards to answer your questions. Overall we are very excited about our progress and the outlook for 2019. I'll open today's call with a summary of our 2019 objectives as well as some high-level commentary on how we are executing our plan to create value for our shareholders. It's important that you understand in Encana's strategic direction the 2019 deliverables we are working to achieve and know our deep commitment to execution. Following these opening thoughts Sherri will cover our financial results for the quarter. She will provide more clarity around both pro forma and reportable results. As…

Thanks. As Doug said, we are off to a strong start in 2019, and our production costs and capital investments are all on track. We realize that this was a noisy quarter and somewhat difficult to model. So let me provide a few explanations. For the quarter, we had a net loss of $245 million or $0.20 per share. When excluding the impact of certain items, our non-GAAP operating earnings were $165 million or $0.14 per share. Significant drivers of the net loss were noncash unrealized losses on risk management of $427 million before tax, as well as restructuring and acquisition related costs totaling $144 million. These costs were in line with our projections and we do not expect to incur material additional costs through the rest of the year. Cash from operating activities for the first quarter was $529 million. Non-GAAP cash flow was $422 million, a 6% increase over the comparable period of 2018. Non-GAAP cash flow was impacted by restructuring and acquisition costs. Excluding these costs, non-GAAP cash flow in the first quarter would have been $566 million, $0.46 per share or $13.44 per BOE. Our costs were in line with expectations, and our run rate for G&A for the remainder of the year was reduced due to greater synergies from the transaction. Our market diversification strategy continued to enhance cash flow margins in the quarter, adding $1.60 per barrel equivalent. Our Permian oil realized price was strong at about 98% of WTI, nearly $4 per barrel higher than the Midland benchmark. Thanks to our downstream marketing efforts. Our Canadian gas price is almost double the AECO benchmark or about 90% of NYMEX, including the benefit of our downstream marketing arrangements and financial basis hedges. As we discussed in February, our capital investments this year are heavily frontend loaded. This is largely a function of two things. First, the high levels of activity in the Anadarko at the time of the transaction close. And second, our two rig programs in Eagle Ford, Duvernay and Williston, that sees that mid-year as we worked to maximize both cash flow and efficiencies for the year. All of our assets are generating free, upstream operating cash flow this year, and our 2019 capital program was designed to optimize free cash flow generation. Now that we have the restructuring and transaction costs behind us, we expect to be free cash flow positive by mid-year. I'll now turn the call over to Mike McAllister, for an operations update.

Thanks, Sherri and good morning, everyone. Let me start with some commentary, what we call the Encana advantage. This helps define how we approach our business and how our proven practices differentiate us from our competitors. Our goal is to lead in all areas where we operate, and most recently in the Anadarko. We are firm believers in the multi-basin model. This allows us to rapidly apply best practices across the company. When we acquired Newfield, we had some distinct ideas on how we could significantly improve operating practices to reduce costs. These practices are commonplace for us in the Permian and Montney but were not being deployed in the Anadarko. On day one, our teams began to implement significant changes. This slide is an example of some of the big wins we have already delivered with our Anadarko completions. Recognize, we inherited a handful of pads that had been drilled but not yet completed. Encana has a robust supply chain management team in place, and we put them to work on the Anadarko during the integration. We have quickly moved to local self-sourced sand and chemicals, reducing costs by as much as $400,000 per well. We're using Propex boxes on location to ensure timely delivery of sand and to reduce handling costs. We modified the overall pad dimensions to improve traffic flow and safety. This has reduced the amount of time necessary to offload sand during frac operations. With our high intensity frac model, it's important to move more water to location and more fluids off location during flow backs. We have moved to dual flow lines to increase water available during fracs by over 25%. We set a record pump rate in the first quarter for the basin of 115,000 barrels in a 24-hour period with a single…

Thanks Mike and congratulations to you and your team, both old and new for making incredible strides to improve Anardarko basin returns in such a very short period of time. Can't wait to see what you're going to do in the second quarter. We're off to a strong start and feel very good about our execution. Our key accomplishments are listed on the left hand side of this slide. In addition, we have some significant milestones that we are looking forward to reporting on later this year. Let me quickly reiterate where we are today. Higher oil prices will not lead to more capital spending. Our capital budget is fixed and we believe that Encana has the right balance of liquids growth, free cash flow, and return of cash through our $1.25 billion share buyback program. We are about 60% complete on our buyback and are committed to our quarterly dividend, which we intend to increase as our company grows over time. Our model is sustainable. The synergies we identified in the Newfield transaction are real. We achieved our target of lowering well costs by $1 million in the Anadarko and are highly encouraged about our ability to do more. These reductions in cost are materially increasing our rates of return and today make it competitive with any liquids-rich play in North America. We have increased our expected annualized G&A synergies to $150 million, surpassing our original estimate by $25 million. It's still very early and we expect to find more synergies as our teams innovate, drive costs lower and returns higher. Thank you for listening and now the team would be happy to take your questions.

[Operator Instructions]. Your first question comes from Greg Pardy with RBC Capital Markets.

Thanks very much for the rundown just on the Anadarko through the balance of the year then could you frame a little bit of what we should be looking for just in terms of milestones and so on. Just a little bit more color around that would be great.

Yes Greg, I think that the first thing is just and we're kind of break this into pieces, right? I think clearly we're very pleased on the progress on the G&A front, we came out of the gate quickly. Not only did this help the business but it removed the uncertainty out of the organization, which I also think contributed to the outstanding results, Mike's already talked to, but we're still looking for more there and as we look and find more we'll talk more about that. Operationally, Mike has already indicated that we've already delivered wells consider with -- the savings considerably greater than $1 million per well. We're not quite ready to expand that target just yet but we obviously see the potential to do so as we get a bit more time under our belt. The biggest thing there is as Mike highlighted. Many of the ways we execute we could only apply to the completion side because we were working on wells at Newfield that are already drilled now. Now we're actually in the first cube. Those cubes are -- which is a combination of everything we do on the surface with our subsurface concepts. We're drilling our first ones now. That takes about 90 days to get them on production. Then as you know we're not believers in IP24s and flashy rates. We're believers in showing sustainable results, which means it will take a couple of months of data. So that puts you into the fall, that's a big milestone. Across the rest of the business, things are -- our core assets with the Anadarko sort of now down to that level loaded program; the Montney and Permian are there. A lot of the peaky activity, which is just designed to drive the maximum efficiency in our other assets, we're sort of beginning to wind that down. And you'll see the production benefits of that here in the second and third quarter. So that's the broad shape of the year, Greg.

And then just as a follow-up then, a little bit unrelated and I'm asking two questions, I know. But dispositions, I know you don't talk about M&A, but you did mention that your stock represents compelling value right now, you're eating through the share buyback pretty quickly. Is there any potential then that, the repurchases become -- the program becomes augmented if you end up selling assets later in the year?

Well Greg, as I indicated, we'll use that capital frame and see where we are. The other thing that you have to be aware of, we have to get regulatory approval for that buyback, we were authorized to buy back 149 million shares. To go beyond that we have to go get approval to do that. So that's not just within our choice. The other thing to note is we do have $500 million of debt due here in May, which we intend to retire. So we use that frame as we go through there. The last thing I just say is some of our other assets are incredibly high-margin, have great opportunities in them. They're not growth very resourceful we're very, very clear on that. But they also generate substantial free cash flow. So we also have to consider that as we go forward.

Your next question comes from Brian Singer with Goldman Sachs.

Following up on Greg's question there with regard to the share buybacks but also just broadly use of capital, you're pretty clear that the higher oil price is not going to translate into a change in the CapEx budget. What would they translate into? Would that be potentially for considering or asking for approval to accelerate the buyback, would that be held for debt pay down or are there opportunities on the acquisition fronts that you see out there?

We'll use that frame. And the reason I was kind of highlighting the debts that's due here in May, is we are slightly above today our leverage target. So that will potentially be one use of those additional fronts as well. So we first need to get through the current program, we need to see as the year develops, there is obviously volatility in the commodity price but we'll use that frame and as we go to make that decision. And at the moment we're about, as we highlighted, about 60% through the buyback program.

And then my follow-up is in Slide 6 and 7 you showed the Anadarko and Permian oil performance over the first 90 days that's broadly in line with your type curve. Could you break that down into how the oil piece and the NGL piece more specifically are performing relative to type curve?

Yes, I'll let Mike kind of cover that. But basically -- actually if you look at our Anadarko liquids cut in the first quarter it was higher than it was in the fourth quarter. But Mike, do you have any comment about well performance?

Actually our liquids cut in the Anadarko today is 62%, which is even higher than we were in Q1. But both to answer your questions there Brian, both liquids and NGLs are absolutely in line with our type curve so from a percentage standpoint. So no surprises or concerns there. And as I actually mentioned maybe a little struggle in the Anadarko.

Your next question comes from Asit Sen with Bank of America Merrill Lynch.

So Anadarko questions and by the way thanks for all the details, but we're thinking about 31 net wells that came on stream in Q1 and the full year target is 100 net wealth on stream. How should we think about the cadence for the balance of the year? And when we're thinking about cubes, how many cubes are we sort of broadly thinking second half, any sense on the side of the cubes?

Yes, okay. A couple of things. I think that because of the high level of drilling and completion activity in 1Q, we actually have a considerable number of wells coming on here in 2Q and 3Q. And then as we go through the year we'll get to a more level loaded cadence. Mike I don't know if you have any comment about the actual number of cubes?

Yes. I think right now on the plan that we have a four cubes plan between now and the end of the -- now and the end of the year.

Okay. Thanks.

And then the second question is on, Mike you mentioned about doubling frac stages per day, and lowering your downtime, is there a way to quantify some of those improvements that you've already achieved -- met in the Anadarko basin?

Yes, just to historically, the average was 4 frac stages per day. And we with our advanced completion design from what -- that we applied combined with how our logistics on sand delivery and increasing our water delivery went actually from 80 barrels a minute up to 100 barrels a minute. We went from 4 frac stages a day up to 8. In fact we're pushing to 10 stages a day. That's a combination of higher volumes but also really attack non-productive time. And then applying some of the same techniques that we apply in the Permian and the Montney on our cubes there.

Yes. And I just add one thing. Just as you translate that into things like cost, Mike I think in one of the slides kind of references the number of days we're reducing the cycle time just within completion efficiency. Remember a large amount of the equipment on site when you're completing wells is paid for by the day. So when you get that off your references even taking 7 days out of the completion of a small pad. That seven days' time, a fairly big number, and should actually results in direct cost savings. And this is using techniques we've proven elsewhere in how we execute, so we talk about the cube it's not just what goes on in subsurface, it's actually the way we approach development of unconventionals. And it's this sort of ruthless approach to finding new efficiencies, largely through innovations. And some of them are as simple as things, like Mike mentioned, like one way road systems on pads, which are not only safer but a lot more efficient. And others are integrating every single step of the chain to make sure that you're never actually down, you're always operating. One of the things we track closely is pump hours per day. Many people are pleased with 12 to 14, we like 18 to 20. And that does save us money. It also makes everything we use in the supply chain more efficient. And I think what we're trying to demonstrate here is, what's worked everywhere else in our enterprise, we've already proven now that it works in the Anadarko.

Actually I've got one follow up if I may. On Slide 7, you have the cycle times in the Permian where Anadarko -- where Encana shows up pretty good. Could you remind us what your completion cycle times in the Permian today are?

Well what we do is we target -- what we look out for cycle time is when do we begin activity on the pad and when do we start production off the pad. So -- and we target across the company 90 days or less is what we target. And there's two reasons for that, one obviously, it's helpful on the returns and the financial performance. But the piece that many overlook is, it means we get data back really quickly. So when we bring a cube on after 90 days, we are actually getting data back that's informing the very next cube. As we've said, we do not believe in this concept of standardization, we actually believe you're constantly innovating and learning, and you need to get data back to do that. And this is one of the big distinct differences between cubes and rows as we deploy them. But that's what we target across the company.

Your next question comes from the line of Gabe Daoud with Cowen.

Maybe just starting in the Montney condensate production about 33,000 barrels a day in the quarter, maybe a bit lighter than what I was thinking, and obviously it's down from 4Q on some of the initial initiatives that you guys talked about. And maybe lack of investment. But can you just talk a little bit about expectations for condensate production throughout the rest of the year? And maybe even on a longer-term basis relative to your current midstream capacity? And then is there anything new going on there from a completion or a spacing perspective?

Yes Gabe, I think that, what Mike's really been trying to highlight is the last several quarters we probably drilled some of the best wells we've ever drilled in the Montney, when you look at condensate rates. And this is occurring both in Cutbank Ridge, particularly around Tower and also and in Pipestone. So we've been very, very pleased with well results. Production is plus and minus where we expected to be right now. And if you recall, we're basically -- year-over-year quite a bit of growth reasonably flat through 2019. Michael talks more about that in a second. And then the next big piece of growth is when we bring on the Pipestone plant we're building with Keyera, which will start up in 2021. So that plan has been in place for a while, we're executing on that plan and we're quickly getting to a plus or minus plateau here. But Mike do you want to provide any more detail?

Yes Gabe, currently we're doing, in condensate, we're dealing with 40,000 barrels a day, and in 15,000 barrels of NGL, sort of 55,000 barrels of liquids per day. So things are growing and going to be in the range.

That's helpful, thanks, like that's the April rate on those?

I just give you the, kind of, the current rate.

Just moving back to Anadarko, obviously great signs on synergy capture and you had already discussed a lot about what's going on there. But if well costs today are $6.9 million realistically, like, how much lower do you think that can go? And can you remind us what's assumed in the budget for the year from a well cost basis? And then, I guess, similar to the Montney question in terms of the trajectory of liquids. Obviously there's a focus with oil growth [indiscernible] but any thoughts on when the liquids mix starts to increase further, is it 2Q, and 3Q when you get some of these cubes on? But anything that would be helpful.

Yes Gabe, I think if you -- I mean it's like -- yes, it's like five questions by the way, I think you put --

Sorry Doug.

No worries. I think in terms of cost, we haven't disclosed the exact number we used in the budget in how far we can get below $6.9 million. We want to get -- we've actually drilled some wells considerably lower than that. And Mike's given me, don't you dare give a number just yet, but we need to get a number more under our belt but we see there could to be substantial further reduction. Our model is working incredibly well here. We're very, very pleased with how quickly we've been able to take the cost out. The team's excited. So I think in 2Q look for us to talk more about that. And the only reasoning -- reason of being a bit vague is, we've got, 6 to 8 wells kind of, that's some very, very, low cost numbers, and we'd like to see a few more before we go out, too far on this. But there's a lot of room for improvement here. In addition, almost all the costs we've taken out today to have been on the completion side. You know the completion is the most expensive side of the well. But we're now -- part of the logic was we weren't going to put that effort on reducing drilling cost on 11 rigs, when 7 of those we were laying down. We wanted to get to the 4 we were going to be moving forward with, and focus on completions first. So that's where Mike and the team are now focused. So look for more on this in 2Q, but that number's going to get lower, I just don't want to tell you how far just yet. In terms of liquids and oil cuts, couple of things are going on here. A lot of those wells drilled, obviously, the shape of that program at the start of the year was set by Newfield, we've been very clear about where we wanted to deploy capital. Which is predominately in the Meramec oil window, that's where we'll be focusing on in the remainder of the year and that is an earlier part. Not going to give you any specific details beyond what we've already guided. But we are rapidly pushing the capital into the portion of the play where we're most focused, which is oilier, which should drive that up. And the early results are looking very good, I mean we have done somewhere around a half a dozen wells now with our high intensity completion design. Those wells are just coming on line in the last few weeks, and the early performance is quite strong, so we're very encouraged at this point.

Your next question comes from Jeanine Wai with Barclays.

My first question is on, or I guess both my questions are on capital intensity and PDP decline rate. So in terms of the corporate oil PDP decline rate what is that about now and do you see that improving next year? And I guess one of the reasons why I ask is, how does that compare to that of the core three plays given that you plan to have a bunch of non-core asset sales over the next couple of years.

I think there's just a ton of detail in all that and some of those numbers we haven't disclosed, so what I'll do is I'll just add Steve and the team to follow up with you afterwards.

Okay. And then maybe just a little more broadly then, but sticking to that topic. You've talked in the past about the differences between row development and cube development, and when we look at the capital and continue the business going forward does the transition to cube development in the Anadarko, does that have any effect on the go forward oil base declines, and I'm not sure if you have any data on that transition from the Permian or from your other basins where you implemented it?

No, we really haven't. In fact, if anything it's a benefit because you're sort of getting the optimum spacing in 3D. The other thing, and I'll stress this again, rows in one way to think about a row is it's a whole bunch of cube side by side done at one point in time. The reason we believe that is not the right approach is you end up deploying a lot of capital and actually develop a lot of land with no data back. Our approach would be -- so I'll use an example in the Anadarko, one of our cubes would be 1,280 acres, it'd be two sections, but it would be there. We wouldn't be developing the two sections next year at the same point in time, we would go be developing elsewhere on our acreage. 90 days after doing that, we're getting production data back, we can monitor that performance, we can then -- then we can then adjust, and adapt and improve the next cube next to it. So the chances of wherever having a large bust in how you do your development program is much, much lower. We're typically deploying across the company. Our cubes are anywhere normally from about $75 million to $100 million of capital, where a lot of time rows are $0.25 billion of capital. So this is a much better way to not only reduce risk, but to continually optimize as you go forward. And this is what we're moving to in the Anadarko as we go into the second half of the year.

Your next question comes from Jeffrey Campbell with Tuohy Brothers.

Congratulations on a fast start after the acquisition. I just want to ask you about the Montney, I'm just looking at Slide 8. I was just wondering is the production X as in access of type curve, is that a continuation of the fourth quarter '18 IP90 outperformance or is this something in excess of that?

It's actually consistent with that performance. This is -- if you go back to the February call, Mike talks some about this then and we've continued to see these really strong results as we've added more and more to this. And once again it's kind of tied back to the last couple of questions. This is the advantage of our approach to development, because we have continued to adapt and adjust how we do these developments and we see these results show through. So these numbers in fact, I'm sure some of you guys will end up doing this, but go overlay that type curve, the liquids piece with any liquids type curve anywhere, and then drop in the fact that the wells cost $4.3 million, which is $2 million to $3 million cheaper than a Permian well, and then you add in that 5% royalty and then you'll understand why we like to deploy capital against our Montney acreage.

Right. How much more data do you think you need to just kind of say that we need a new type curve here?

Well we're all kind of smiling because this was the role Sherri has played for a while with Mike. And a common phrase for her in many reviews, is when are you going to update the type curve. But it's something the team are looking at as we get more wells here. One thing to note though, remember in the Montney that we have a certain amount of processing capacity. So in many ways like our -- around Tower our big plant there is full, it's completely full. All this means is, it's going to take less capital to keep it full, because we don't have additional processing capacity, and the next big piece of that will come on in Pipestone in 2021.

I want to ask a little bit different question. It seems to me that the one asset you have in the Other category that actually has some growth potential is the [indiscernible], and I've talked to you guys about this. But I was just wondering if you could provide any outline or update or however you want to frame it regarding your ongoing work to try to move more volumes out of the [indiscernible] because we know there's a transportation constraint at this time.

Yes, our view of the [indiscernible] is it's not a growth asset today. We think it's got -- it's very, very interesting -- Newfield did a great job, capturing a large piece of -- if there is a play to grow here they captured the core of it. But it's something we're trying to fully understand both in the subsurface and in how to get that product to market where you get paid properly for it. So today the capital investment is very low and while we try to fully understand it and where it will fit in the future.

We have time for one more question. Your last question comes from Menno Hulshof with TD Securities.

I've just got a follow-up on your remaining Anadarko cubes for 2019. So what can we expect in terms of design and how much variability could we see for the four that you have in the Q3 at the end of the year. Is this a plan here to get more aggressive with each successive cube or to leave the design relatively unchanged?

Yes Menno, that's a good question. This year we're not planning to push being aggressive. What we really want to do is, demonstrate the power of taking this cost out and how that makes the capital return on the Anadarko compete, and show some consistency in the results, because we know that people are concerned about that. This is not the year to push out the edge. As we look to '20 and learn more, we may do that. So I think that what you should be looking for is this kind of relentless push and showing how efficiently we can do this and consistency in results.

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

Thank you, Operator. And thank you everyone for attending this morning's call. You can sense we have a lot of enthusiasm about the back half of '19 and we look forward to updating you through the year. Thank you.

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