Earnings Call: Q1 2019

Apr 30, 2019

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. At this time, all participants are in a listen only mode. Following the presentation, we will conduct a question and answer session. Members of the investment community will have the opportunity to ask questions and can join the queue at any time by pressing star 1. 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 expressed 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 Q1 2019 conference call. This call is being webcast and the slides are available on our website atencana.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'll now turn the call over to our President and CEO, Doug Suttles. Good morning, everyone. Thanks, Steve. Thanks for joining us today for our Q1 2019 conference call. I'm joined today by other members of the executive team. As you know, our longtime CFO and friend Sherry Brillon is retiring after 33 years with Encana. She will be providing our financial update one last time, but kindly offered to let Cory answer all of your difficult questions. Sherry 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'll do our best to help with that. And of course, Steve and the team will be available afterwards to answer your questions. Overall, we're 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 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 form a and reportable results as well as the reorganization and transaction costs associated with the recent Newfield acquisition. Both Sherry and Corey will be available during Q and A to take your questions. Mike McAllister, our COO will follow with an operational update. Here's an overview of what we focused on this year. 1st and foremost, we are laser focused on delivering the synergies we laid out with acquisition of Newfield, which closed in mid February. We moved rapidly to capture the significant value we saw behind this strategic combination. We outlined 2 key buckets for the synergies. The first was G and A. In just 8 days post the Newfield closing, we had essentially completed the reorganization and communicated to employees about their future with Encana. Recall that our initial target for annualized G and A reductions was $125,000,000 Today, we have increased our projected G and A synergies to $150,000,000 annually. Although the largest components were people related costs and the elimination of duplicative roles, we also streamlined our structure throughout the company, reducing total headcount by 15% and leadership roles by 35%. Today, we have fewer senior leaders than Encana pre merger. In addition, we captured significant non people cost. These include canceling or subleasing unneeded office space, insurance cost, audit and credit facility fees, board fees, reducing consultant and data license spending and lower dues and trade association cost. The list is long and we are confident that we'll find even more efficiencies as we go forward. You will notice in our guidance that we've improved our G and A outlook to $75,000,000 per quarter. The benefits of our G and A reductions will flow through the income statement in the 2nd quarter. To put the significance of the total $150,000,000 of annualized G and A savings into perspective, it equates to more than our annual total dividend. When our business is more efficient, we can return more cash to our shareholders over time. The second bucket was our view that we could reduce STACK well cost by at least $1,000,000 per well. From the moment the deal was announced last November, our team started working together to positively impact operations at every level. Although I will save the lion's share of the update for Mike, I can tell you that we have already achieved our stated well cost savings and we have line of sight to much greater numbers as we fully implement our proven cube model. We are highly encouraged about what we can do going forward. Our second objective is to generate free cash flow and return capital to shareholders. This will be the 2nd year in a row that Encana has generated free cash and returned a significant portion to its owners. It's not something we are planning or promising to do, it is something we've done and something we are doing again in 2019. Many of our peers are working hard to get their business models to where ours is today. All of our assets are generating free cash flow today and at lower commodity prices that you see on your screens now. Since kicking off our $1,250,000,000 share buyback program in March, we have already executed over 60% of that program, repurchasing 91,000,000 shares of common stock at an average price of $7.19 per share. We see compelling value in Encana's stock today. In fact, we strongly believe that buying our own equity is an incredible value. Although higher oil prices are certainly a nice tailwind, I want to be very clear, higher oil prices will not translate into higher capital spending. We believe we have a compelling plan for 2019 and improved commodity prices will just further enhance our free cash flow. We think our unique combination of liquids growth, free cash generation and a return of cash to our owners provides exactly what the market should reward. We fully intend to stick to this plan. In our slide deck, please revisit the page that depicts our use of cash. We have a disciplined top down approach to capital allocation and are very deliberate in our investment choices and use of cash. This matrix show we how we prioritize the use of cash from ensuring financial strength to growing future dividends to opportunistic share repurchases and to high return drilling programs. This framework will guide our decision making. Our third objective is to deliver strong results from our core growth assets, the Anadarko, Permian and Montney. These liquid rich developments will constitute about 75% of our capital investments this year and are expected to generate about 15% liquids growth at high returns. Year to date, these assets are performing well and production is ahead of the internal plan that was used to set our guidance. Recall that in February, we noted capital would be front half weighted for a couple of reasons. First, we inherited a high level of activity from Newfield. 2nd, our capital programs and other assets were designed to optimize capital efficiency, which results activity levels in the first half of the year. As we move through the second quarter, we're seeing a more level loaded profile for our core growth assets and activity in our other assets will wind down. It is important to note that this capital profile is part of the plan and we are on track to meet our full year capital and production guidance. At closing, Newfield had 11 rigs and 8 frac spreads running in the Anadarko Basin. We rapidly level loaded activity and today have 4 rigs that will be supported by 2 frac spreads for the remainder of the year. Importantly, with the big efficiency gains we are seeing, we will drill and complete nearly as many wells under this scenario as the latter. I can tell you that Mike McAllister is looking forward to sharing his update with you this morning. As you know, our 2018 capital program had lower activity levels in 4Q. The slight rollover in production you see in our 1Q numbers is a direct result of this. Again, this was expected and is in line with the guidance we provided you at the end of February. For the Q1, our pro form a production averaged 567,000 barrels oil equivalent per day. We have included the reportable stats in our release and slide deck. This is in line with our expectations. With many of our well pops in both the Permian and the Anadarko occurring in March, our mid year run rates will be significantly higher. You can see this reflected in the guidance for the remainder of the year. Although our primary driver is certainly not production growth, rest assured we are on track to deliver what we promised for both production and capital. And lastly, but extremely important, we are working to deliver our 6th consecutive safest year ever. There too, we are off to a good start. Now I'll turn the call over to Sherri for the financial update and some additional clarity around the transaction related costs. 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 $245,000,000 or $0.20 per share. When excluding the impact of certain items, our non GAAP operating earnings were $165,000,000 or $0.14 per share. Significant drivers of the net loss were non cash unrealized losses on risk management of $427,000,000 before tax as well as restructuring and acquisition related costs totaling $144,000,000 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 Q1 was 529,000,000 dollars Non GAAP cash flow was $422,000,000 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 Q1 would have been $566,000,000 $0.46 per share or $13.44 per BOE. Our costs were in line with expectations and our run rate for G and 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 was 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 front end loaded. This is largely a function of 2 things. First, the high levels of activity in the Anadarko at the time of the transaction close and second, our 2 rig programs in Eagle Ford, Duvernay and Williston that cease at the mid year as we work 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, Sherry, 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 1, 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 have 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 source sand and chemicals, reducing costs by as much as $400,000 per well. We are using 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 flowbacks. We have moved to dual flow lines to increase water available during fracs by over 25%. We set a record pump rate in the Q1 for the basin of 115,000 barrels in a 24 hour period with a single frac crew. As a result, we have nearly doubled the number of frac stages pumped per day and reduced non productive time by about 40%. We restructured key service agreements leveraging our size and scale across multiple basins. In just a matter of weeks, we proved that the Encana advantage can work in the Anadarko. We maintain targeted savings through significant operational changes to completions. We are far from done and look forward to pushing costs even lower when we manage both the drilling and completions in our new cubes. Applying the Encana advantage has allowed us to reduce well cost by $1,000,000 and substantially more than $1,000,000 in some very recent wells. The cost reductions I referenced on the prior slide can be seen in detail here. Phase 2 kicks off today as we recently spud our 1st cube development in the Anadarko Basin. We have line of sight to additional savings that we can capture during drilling operations with full implementation of our proven practices. We look forward to sharing our production results from these cube developments with you later this fall. As we said before, our synergies with acquisition of Newfield were based on lowering well costs significantly, not improving well performance. When you look back at Newfield's performance in the STACK, the wells have performed very well and are consistent with type curve. On this slide, we applied a performance from a number of from another 49 gross new stack wells that were placed on production during the Q1. In total, we now have long dated production on more than 150 operated infill wells, which provides us with high confidence in the rocks. As you can see, performance remains consistent with type curve. Both the liquids cut and the oil yields are in line with expectations. In the Permian, our production in the quarter was about 91,000 BOE per day. Production was a little lower than our year end exit rate due to two things. First was our reduced capital investments in late 2018. 2nd was related to 3rd party curtailments that extended into late February. These plant issues reduced volumes by about 3,200 BOE per day. We started 33 new wells during the quarter and continue to see strong and consistent performance. Since the quarter end, our production has increased to nearly 100,000 BOE per day and reflects our higher expected run rate through the remainder of the year. On this slide, we gathered cycle time data from Encana and a large subset of our peers in the basin. When comparing well spud to first production, we are a clear leader with our operations. This is the Encana advantage that I referenced earlier. And this is what gives us high confidence in our ability to dramatically reduce costs in the Anadarko. We are producing 100,000 BOE per day with plans to drill more than 100 wells, just a 4 rig program. Others are running 2 to 3 times the rigs to achieve the same outcome, and Canada is a leader in efficiency. In the Montney, we continue to see material gains in efficiencies and well productivity, where Encana has drilled more than 6.50 wells over the last 12 years. Our organization is constantly innovating. During the quarter, we placed 15 wells on production and expect to complete about 75 wells in 2019. Recent well performance has been strong, particularly in Tower, where we are focused on a liquids rich window. Well costs during the quarter averaged $4,300,000 which is in line with our expectations. Well results against our type curve are shown on this slide. Some of our recent wells are producing as much as 1500 barrels of condensate per day. We have a very similar story to tell the Montney around reducing cycle times in both Tower and Pipestone. Since the Q1 of 2018, we have improved cycle times by 50%. Again, this is what gives us high confidence in the Anadarko. Importantly, the Montney provides us with very competitive rates of return. Oftentimes, people overlook the fact that well costs are nearly half of what they are in the Permian with royalty rates around 5%. Yes, there are some challenges in Canada today, but our focus on liquids and the forward planning we have done through our marketing team have largely insulated us. The Montney competes well for our capital, and we are careful to time our investments with our takeaway options. That concludes my operations update. I will turn the call back over to Doug for closing remarks. Thanks, Mike, and congratulations to you and your team, both old and new, for making incredible strides to improve Anadarko Basin returns in such a very short period of time. Can't wait to see what you're going to do in the Q2. We are 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 $1,250,000,000 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 cost by $1,000,000 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 and A synergies to $150,000,000 surpassing our original estimate by $25,000,000 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. Your first question comes from Craig Pardy with RBC Capital Markets. Your line is open. Thanks. Good morning. And I guess first off, just all the very best to you, Sherry, and thanks so much for the help over the years as well. 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. Thanks. Yes, Greg. I think that the first thing is and we'll kind of break this into pieces. I think clearly we're very pleased on the progress on the G and 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 $1,000,000 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 the wells that Newfield had already drilled. 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 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. Okay. That's helpful, Doug. And then just as a follow-up then, a little bit unrelated, and I'm asking 2 questions, I know. But dispositions, I know you don't talk about M and 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 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 149,000,000 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 $500,000,000 of debt due here in May, which we intend to retire. So we'll use that frame as we go through there. The last thing I'd just say is, some of our other assets are incredibly high margin, have great opportunities in them. They're not growth areas for us. 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. Okay, terrific. Thanks very much. Your next question comes from Brian Singer with Goldman Sachs. Your line is open. Thank you. Good morning. Good morning, Brian. Following up on Greg's question there with regards to the share buyback, but also just broadly use of capital, you're pretty clear that higher oil prices aren't 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 front that you see out there? Yes, Brian, we'll use that frame. And the reason I was highlighting the debt 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 funds as well. So we first need to get through the current program. We need to see as the year develops, there's 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 today, about 60% through the buyback program. Great. And then my follow-up is in Slide 67, you show the Anadarko and Permian well performance over the 1st 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 Q1, it was higher than it was in the Q4. But Mike, do you have any comment about well performance? Actually, our liquids cut in 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 curves, so from a percentage standpoint. So so no surprise or concerns there. And as I actually mentioned, maybe a little stronger in the Anadarko. Great. Thank you. Your next question comes from Asit Sen with Bank of America Merrill Lynch. Your line is open. Thanks. Good morning, gentlemen. So, 2 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 wells 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 in second half? Any sense on the size 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 in the plan that we have about 4 cubes planned between now and the end of the year. Okay. Thanks. Great. 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 in the Anadarko Basin? Yes. Just 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. Appreciate it. Yes. And I'd 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 where 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 7 days' time a fairly big number. And so it actually results in direct cost savings. And this is using techniques we've proven elsewhere in how we execute. So when we talk about the cube, it's not just what goes on in the 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. Great. Thanks, Doug. Actually, one follow-up, if I may. On Slide 7, you have the cycle times in the Permian 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 at 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. 1, 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're 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. Thanks, Doug. Your next question comes from Gabe Daoud with Cowen. Your line is open. Hey, good morning, Doug. Good morning, everyone. 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 midstream issues 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 spacing perspective? Yes, Gabe. I think that what Mike's really been trying to highlight is the last several quarters we've 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 Cubank Ridge, particularly around Tower and also in Pipestone. So we've been very, very pleased with well results. Production is plus and minus where we expect it 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 on condensate, we're doing with 40,000 barrels a day and then 15,000 barrels of NGLs or 55,000 barrels of liquids per day. So things are growing and going to be in range. That's helpful. Thanks, Mike. That's the April rate on those? I just gave you the kind of the current rate. Okay. Got it. Got it. Okay. That's helpful. Thanks. Just moving back to Anadarko, obviously, great start in the synergy capture and you had already discussed a lot about what's going on there. But if well costs today are $6,900,000 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 trajectory of liquids, obviously, there's a focus with oil growth out of the asset, 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 there would be helpful. Thanks a lot, guys. Yes. Gabe, I think as you I mean, it's like 5 questions by the way, I think. Hi, Doug. No worries. I think in terms of cost, we haven't disclosed the exact number we used in the budget and how far we can get below 6.9. 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 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 is excited. So I think in 2Q look for us to talk more about that. And the only reasoning reason I'm being a bit vague is we've got 6 to 8 wells kind of at 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 to date have been on the completion side. Now 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 is going to get lower. I just don't want to tell you how far just yet. In terms of liquids and oil cuts, a 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 want to deploy capital, which is predominantly 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 online in the last few weeks and the early performance is quite strong. So we're very encouraged at this point. Great. Thanks so much guys. Appreciate it. Your next question comes from Jeanine Wai with Barclays. Your line is open. Hi, good morning everyone. Good morning. Good morning. 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 3 plays given that you plan to have a bunch of non core asset sales over the next couple of years? Yes. 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 ask 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 intensity of 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? 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 3 d. 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 cubes 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. 1 of our cubes would be 12 80 Acres. It'd be 2 sections. But it would be there. We wouldn't be developing the 2 sections next to it at the same point in time. We'd 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 ever 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 $75,000,000 to $100,000,000 of capital, where a lot of time rose are $250,000,000 of capital. So this is a much better way 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. Okay, great. Thank you for taking my questions. Thanks. Your next question comes from Jeffrey Campbell with Tuohy Brothers. Your line is open. Good morning and congratulations on the fast start after the acquisition. I just want to ask about the Montney. I'm just looking at Slide 8. I was just wondering is the production in excess of type curve, is that a continuation of the Q4 2018 IP90 outperformance or is this something in excess of that? Yes, Jeff, good question. It's actually consistent with that performance. We've this is if you go back to the February call, Mike talked some about this then and we continue 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 $4,300,000 which is $2,000,000 to $3,000,000 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. And 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 a role Sherry's played for a while 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. All right. Yes, that's a good observation. The other question I wanted 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 Uinta. 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 Uinta because we know there's a transportation constraint at this time? Yes. Our view of the Uinta 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. Question. Your last question comes from Menno Hulshorn with TD Securities. Your line is open. Thanks and thanks for taking my question. 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 4 that you have in the Q through the end of the year? Is the plan here to get more aggressive with each successive cube or to leave the design relatively unchanged? Yes, Meno, 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 'twenty 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. Okay. Thanks, Doug. That's it for me. At this time, we have completed the question and 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 'nineteen and we look forward to updating you through the year. Thank you. This concludes today's conference call. You may now disconnect.