Earnings Call: Q2 2018

Aug 1, 2018

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Encana Corporation's 2nd 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. 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 from 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 Corey Code, Vice President of Investor Relations. Please go ahead, Mr. Code. Thank you, operator, and welcome, everyone, to our Q2 results conference call. This call is being webcast and the slides are available on our website at encana.com. Before we get started, please take note of the advisory regarding forward looking statements in the news release and at the end of our webcast slides. Further advisory information is contained in our annual report and other disclosure documents filed on SEDAR and EDGAR. I also wish to highlight that Encana prepares its financial statements in accordance with U. S. GAAP and it 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 Sherry Brillon, our CFO will highlight our financial performance Rene Zemlyak, our EVP of Midstream Marketing and Fundamentals, will highlight the benefits of our marketing strategy And Mike McAllister, our COO, will then describe our operational results. We'll then open the call up for Q and As. We'll now turn the call over to Doug Zuttles. Thanks, Corey, and thanks, everyone, for joining us this morning. Our second quarter results demonstrate why Encana is quickly differentiating itself as an operator that excels in execution at scale. We put forth an ambitious objective at the start of the year to achieve 30% annual production growth while spending within cash flow. Our strong performance this year has put us in a position to meet that ambitious growth target, and we now expect to generate free cash flow this year. Our cash flow continues to grow through a combination of increased liquids mix, our relentless focus on efficiency and our approach to maximizing realized prices. This means that we translating higher commodity prices into higher margins. As a result, we now expect our 2018 cash flow margin will average about $16 per barrel oil equivalent, up from our previous target of $14 Activity across our core assets were at peak levels during the quarter, setting us up to deliver 400 1,000 to 4 despite a planned turnaround at one of our facilities, and we remain on track to achieve an average liquids rate of 55,000 to 65,000 barrels per day in the Q4. We continue to see strong well results from our cube development approach in the Permian, where we are currently producing at record levels of more than 90,000 BOEs per day. Our Eagle Ford asset, which achieves the highest price realizations in our portfolio, returned to growth in the Q2 and is posed to continue growing for the rest of the year. Finally, in the Duvernay, we are seeing strong initial well results from our 2018 program where we have recently ramped up completions activity. Once again, our first mover approach to market access and price risk diversification paid off during the quarter. This was particularly true for our Permian oil volumes and our Canadian gas volumes, which both saw realized pricing above their respective benchmarks. The combination of physical transport and financial basis hedging gives us confidence in our ability to achieve our growth plans while maximizing our margins. We are carrying significant momentum into the second half of the year, and we continue to grow liquids volumes and cash flow. We are very pleased with our results so far this year, but as always, we are working to make them better. We believe that our performance is the result of our unique combination of innovation and discipline. This enables us to both create value and manage risk. It is proof that our strategy is working. The pillars that we built the business on 5 years ago are just as important today as they were then. We have established a strong track record as an operator you can trust to meet our targets, to innovate in real time and to maximize the value of our acreage. Our cube development approach enables us to do all of these things while developing at scale. It is quickly being adopted as the industry standard for stacked plays. We believe that being in the best rocks is fundamental to delivering leading results and returns. As such, we have constructed a world class portfolio with a deep inventory of premium return location. The great thing about being in the core of the best plays is that over time, these plays get better. As Mike will discuss later in the call, we are seeing strong well results from new zones in the Permian, inventory upside in the Eagle Ford and more liquids rich targets in the Montney. All of these opportunities present upside potential to our 5 year plan. We believe there is real value in having a focused multi basin portfolio. Having multiple core positions gives us tremendous advantage when it comes to managing risks such as to market access and infrastructure. It gives us enormous flexibility, including the ability to redirect capital. Our focus on market fundamentals enables us to maximize our margins, provides reliable and diversified market access for our products. Our marketing arrangements include a lot of flexibility and we've managed our price exposure to specific basins. For example, in the quarter, our Permian realized oil price was 103% of WTI. We remain extremely disciplined in how we allocate capital. Essentially, all of our capital goes to our core plays. When we consider investing additional capital in a higher commodity price environment, we must first be convinced that the majority of the incremental price will flow to margins and returns, that we maintain our efficiencies and our performance. Underpinning all of this is our commitment to ensuring we have a strong balance sheet. This year, our leverage will continue to drop even as we invest to significantly grow production and buy back shares. By year end, we expect to be approaching 1.5 times net debt to EBITDA. All of this adds up to making Kenna a unique E and P company, a company that is delivering strong returns, quality cash flow and production growth, a strong balance sheet, all while building a track record of innovation, both technically and commercially. I'll now turn the call over to Sherri, who will discuss our financial results. Thanks, Doug. We are extremely pleased with our performance this quarter. We came into the year with the expectation that we would balance our capital program with cash flow. We now expect to generate free cash flow in 2018 at strip prices. As Doug mentioned in his opening remarks, we increased our full year expected cash flow margin to approximately $16 per BOE. This is up from $14 per BOE. Our margin expansion is driven by our continued focus on growing higher value oil and condensate production. In the Q2, liquids made up 46% of our total production. Our risk management program also supports our margin expansion. We saw another quarter of strong realized prices owing to our market diversification strategy and our basis hedge program. A disciplined focus on managing costs ensured the higher liquids prices we receive went directly to our margin. 2nd quarter cash flow margin was also positively impacted by tax and related interest recovery of $75,000,000 This contributed a 2.44 dollars per BOE uplift to our 2nd quarter cash flow margin of $19.09 per BOE. Overall, we have demonstrated a track record of holding the line on costs to ensure price increases expand our margin. Our 2nd quarter cash flow of $586,000,000 or $0.61 per share demonstrates the impact of our liquids driven margin expansion. Our net earnings fluctuated to a loss this quarter, primarily due to an unrealized mark to market loss on risk management of $326,000,000 versus a gain in the Q1 of $68,000,000 before tax. Partially offsetting this impact is a smaller unrealized FX loss than Q1. These non cash items tend to fluctuate quarter to quarter, but our upward trend to operating earnings and cash flow demonstrates our strong results. Our capital program remains on track with guidance. Our 2018 capital plan had more activity in the first half of the year. Mike will cover this in more detail in a few minutes. We continue execute our share buyback and have now completed half the program. We expect to complete the $400,000,000 authorization by the end of the year. We're extremely pleased with our financial performance and we expect to finish the year off strong, positioning us well for 2019. Encana's liquids growth is driving improved margins and cash flows. When we look back, our production mix was 37% liquids in the first half of twenty seventeen. This has increased to about 45% year to date. This shift to liquids has a significant impact on our revenues and margins. In fact, even if we keep prices constant period over period, our liquids revenue would be up $240,000,000 Adding to that upside is the stronger prices we are seeing this year, which helps further lift liquids revenue another $365,000,000 Our gas volumes are lower than a year ago, but as you can see in the following slide, we are shifting to higher liquids keeping costs flat, which enhances our margin and upside capture. Last quarter, we outlined how we focus on capturing margin upside as prices rise. In a commodity business, it's critical that we're able to manage costs even as prices rise. Our objective is to convert higher prices to higher margins in cash flow. The results we are seeing in the first half of the year are showing the benefit of cost control and upside capture. We are driving our operating margin about 39% higher versus the first half of twenty seventeen. In a period of volatile Midland Oil and AECO Gas pricing, we have captured additional margin through a combination of market diversification and basis hedges. Our market diversification generated a net uplift to our margin of $1.60 per BOE year to date over $2 per BOE this quarter. Later in the call, Renee will share an example from our Permian to highlight this strategy. Our increased liquids mix and strength in the benchmark price improves realized pricing, but the key has been to continue our shift towards liquids production without expanding our cost structure, so we drive our margin higher. Our disciplined cost control is continuing to work. Compared to last year, our per unit operating costs are down and our T and P costs are up slightly due to our market diversification strategy. In return for increased T and P costs is the improved realized pricing and lower risk by diversifying our exposure to different markets and higher margins. As we look forward to the remainder of the year, we're confident that we can achieve our cost guidance, which will preserve the majority of price increases as additional margin. I'll now turn the call over to Renee. Thanks, Sherry. Encana's approach to marketing and market fundamentals are core principles of our strategy. Market diversification and basin specific economics impact capital planning and therefore receive a great deal of our attention. We connect market intelligence and risk mitigation to corporate strategy, planning and upstream execution. It is the strong integration across the company that enables us to effectively mitigate regional price risk, including AECO Gas and Permian Oil Dynamics. There are 3 main components to our approach to our commodity monetization. 1st, we ensure physical market access for our production. Practically speaking, this means that we have cost effective transportation and midstream capacity for existing production and a portion of our future growth. 2nd is our drive to maximize price realizations. We focus on cash flow, specifically cash flow margin and we proactively seek to diversify our physical sales points. In the second quarter, our arrangements have mitigated some key basin risks and we've added about 13% to our cash flow. This translated into about $70,000,000 for the Q2 and about $100,000,000 year to date. We also employ a structured financial risk management program to reduce cash flow volatility and manage our balance sheet risk. This includes managing both benchmark price risk and basis differentials. The value of our marketing approach is evident in our 2nd quarter results. In the Permian, our realized price of $70.15 per barrel exceeded the WTI benchmark by more than $2 per barrel and it exceeded the Midland price by over $7 per barrel. This demonstrating our management of basin risk in the Midland. We have achieved this through a combination of firm transportation and financial hedging. Our firm transportation provides exposure to Houston pricing and we have tailored this capacity to grow to match our Permian development plan. Our Midland differential hedge position generated additional cash flow protection ensuring that a combination of our basis and our effective realized price came in above the average WT oil price for the quarter. As we look to the balance of the year and the continued Midland pricing volatility, we are well positioned to ensure that our cash flow risk is well managed. This is just one example of how the team works to mitigate market risk and capture margin. I will now turn the call over to Mike. Thanks, Renee. Across the portfolio, our plant is on track to grow 2018 production by 30% over last year, while now generating free cash flow. We continue to see the benefit of our cube development approach. Our latest cubes in the Permian are delivering strong production performance. In the Q2, we achieved another significant milestone in the build out of the Montney facilities. The Tower North centralized liquids hub came on stream ahead of schedule. This further derisks our second half Montney liquids production ramp and has us firmly on track to achieve 55,000 to 65,000 barrels per day in Q4. As industry activity picks up in the busier basins like the Permian and Eagle Ford, continue to see benefit of our integrated supply chain strategy. Our proactive strategy means that we're not trying to secure new services in a competitive market. In the Permian, our transition to local sand has progressed well. We are currently using more than 90% local sand. In the Eagle Ford, we tested the Groban area and continued to develop the Austin Chalk. Early results are promising and are helping to derisk future increases of our premium inventory. In the Duvernay, we had a successful quarter of drilling activity with new pacesetter performance on extended reach laterals. To achieve the objective of delivering 30% growth, we laid out our 2018 program with our drilling and completion activity weighted to the first half of the year. Having more than half of our activity completed gives us further confidence in being able to deliver Q4 targets. We expect our drilling activity in all four of our plays to be lower in the second half of the year. In the Permian, we are currently running 4 rigs down from 5 in Q1. In the Montney, we currently have 7 rigs running down from 12. In the Eagle Ford, we started the year with 3 rigs and now have 2 operating today. We expect our 2018 Duvernay drilling program to be wrapped up, I should say, up in the next couple of weeks and completions activity be ongoing in Q3. Our Permian production continued to grow in the second quarter. We delivered an average of 88,000 BOE per day in the Q2 and are currently running at record production of over 90,000 BOE per day. This was despite the impacts of expected offset frac activity by competitors in the area. Our success in the Permian continues to be driven by our cube development approach. This approach allows us to exploit maximum value from our stack pay resources while delivering volumes as efficiently as possible. We brought on 3 new cubes in the Q2 in Midland and Martin Counties. The 10 well 2018 Martin cube that we highlighted on the Q1 call produced 1,000,000 barrels of oil in its 1st 99 days. With almost 6 months of production, this cube is on track to exceed type curve IP 180 by over 50%. 3 of our recent cubes have included wells in the Jo Mill zone. We are very pleased with the results we've seen from these wells. Of the 4 Martin County Jo Mill wells we brought on to date, we have seen IP30 production of 1100 barrels per day of oil. Results have been similar to what we would expect from the Middle Spraberry well. The team remains committed to testing new benches combined with well spacing and stacking patterns to determine how to maximize NPV of our land to effectively drain the reservoir. We continue to leverage on our cube development approach to make our operations more efficient. On the drilling side, we achieved a new pacesetter in Q2, drilling over 1 mile of lateral in 24 hours. We consistently benchmark our performance against our peers. Our drilling performance continues to be industry leading. In our recent review of competitor drilling performance from a third party data source, Encana had the fastest average spud to rig release time of our peers at 12.6 days. For wells of similar length, we drilled our wells 3 days faster than the next closest competitor and 5.5 days faster than the average. We continue to take advantage of our land swaps and contiguous acreage position to drill more than 10,000 foot laterals. The average lateral length for our 2018 program is expected to be over 9,200 feet. We are continuing to increase our use of recycled water in the Permian. We now have 7 interconnected water resource hubs, the combined 6,000,000 barrels of storage capacity. Recall that our water hubs are simple catch basin design that only cost about $3,000,000 to construct. We expect to average 40% recycled water use in the basin with some cubes as high as 80%. We've repeatedly pumped 100 percent recycled water stages and expect to recycle over 25,000,000 barrels of water this year. This saves about $1 per barrel on the sourcing side and an additional $0.80 per BOE on lease operating expense because we don't need to dispose of those volumes. Our centralized cube developments mean that we can source and recycle water efficiently and cost effectively. Our Montney program is on track to double liquids production for the 2nd year in a row. In the Q2, we grew liquids production by over 18% versus Q1. Our liquids growth trajectory has continued into the 3rd quarter and we're currently averaging over 45,000 barrels per day. The Tower Liquids Hub came online at the end of June, well ahead of the budgeted startup. The early startup of the facility further derisks our ability to deliver between 55 65,000 barrels a day of liquids production from the Montney in the 4th quarter. The cadence of our drilling program remains largely unchanged from our initial plan. This means that we ramp into the new liquids capacity over the second half of the year as new wells come online. This is the same capital efficient approach that we took to filling our new plant capacity in 2017. Construction of the Pipestone liquids hub remains on track. We expect that facility to start up early in Q4. This will add 10,500 barrels per day of net condensate capacity in Pipestone. Similar to our approach to filling the tower infrastructure, we expect to ramp into the Pipestone hub over the Q4 of this year and into 2019. In the Q2, we successfully executed plant turnaround at our Sexman facility on time and on budget. This had approximately a $5,000 per BOE per day impact on the quarter. Our multi basin portfolio gives us significant optionality where we invest. Similarly, our extensive contiguous Montney land position provides additional optionality within the Montney Fairway itself. The Montney acreage spans maturity window from dry gas to volatile oil. This means that initial condensate ratios in our inventory vary from less than 10 barrels per 1000000 on the low end to as high as 800 barrels per 1000000 on the high end. We have significant inventory in each of the liquids windows, which provides us with flexibility in how we design our development programs. When we laid out our 2018 development program tower, our intention was to roughly balance development between the gas condensate window, our initial CGRs average around 50 barrels per million and the rich gas condensate areas where initial CGRs are between 100 to 200 barrels per million. As Sherry illustrated earlier, liquids production is driving increased revenues and margins for the company. As we continue with our Montney development program, we are continuously driving the program to drill our most liquids rich wells. We remain confident in delivering our Q4 liquids target of 55,000 to 65,000 barrels per day while deriving greatest value from our assets. Agility in adjusting our program to market conditions is another example of how our strategy is working to combine market fundamentals, capital allocation, top tier resources and operational excellence. In the Eagle Ford, strong results from our latest wells have fully offset base declines and the asset returned to growth in the Q2. We brought on 11 wells in Q2, including 1 new Austin Chalk well. Year to date, we have brought on 1 Eagle Ford well in the Groban area and 5 Austin Chalk wells. Our 2018 results in these areas are derisking potential future premium inventory and additional wells are planned for later this year. The average IP90 the 2018 Austin Chalk wells is almost 13.50 BOE per day. These wells are meeting our type curve expectations and delivering an after tax rate of return of 100 percent at $50 WTI and $3 NYMEX. The Eagle Ford and the Duvernay continue to generate free operating cash flow in the Q2 despite the increase in activity in both assets. Access to premium markets, LLS for the Eagle Ford and Chicago for the Duvernay gas have driven margins higher in both plays. In the Eagle Ford, the operating margin in Q2 was almost $40 per BOE, the highest in the company. Activity in both assets is weighted to the first half of the year. In the Eagle Ford, we expect to see additional growth in Q3 and Q4 production similar to the Q4 of 2017 levels. We expect production from the Duvernay to flatten out in the 3rd quarter and to see a return to growth in the 4th quarter similar to levels of Q4 2017. The Du River Verde saw increased activity in the Q2. In Simonette North, we achieved new pacesetter drilling performance. Our latest 6 wells in Simonette North are all over 2 mile laterals. Extended reach laterals are one of the many options in our toolkit that we use to optimize resource recovery. We also brought on a 2 well pad in the volatile oil window in the quarter. We are very encouraged by the initial production results. The average IP30 of the 2 wells is about 10.50 barrels per day of condensate. We expect these wells to unlock additional upside potential in the play. I will now turn the call back to Doug. Thanks, Mike. With the strong results we've achieved in the first half of the year, we remain firmly on track to meet our guidance for 2018. We are very confident in our ability to deliver the growth in liquids volumes we have targeted for the second half of this year. Our margins continue to expand, productivity continues to grow, and we now expect to generate free cash flow this year while delivering 30% annualized production growth. Our track record of efficient execution at scale has established Encana as a leading operator in each of our core plays. Our focus on technical and commercial innovation underpins our ability to drive strong returns at both the well level and for the corporation. Our first mover approach to market access and price risk diversification is paying off across the portfolio by increasing our margins and derisking our 5 year plan. Our focus on market intelligence really has become a competitive advantage. As we look out to 2019, we remain acutely focused on finding ways to make our 5 year plan even better. We are focused on growing value. Our disciplined capital allocation is tightly aligned with an informed perspective our market fundamentals, which is critical to our ability to further expand our margins. A key benefit of having a multi basin portfolio is the optionality it creates for capital allocation. We see this within our plays as Mike outlined in the Montney as well as across the portfolio with the Eagle Ford and its strong margins from LLS pricing. We expect to generate significant cash flow per share growth driven by strong liquids growth and a continued focus on driving efficiency across the business. We are excited that the results we've delivered so far this year have us on track for a strong finish to 2018 and a great launching point for 2019. Thanks for joining us this morning and would now be happy to take your questions. Brian Singer with Goldman Sachs. Your line is open. Hi, good morning. This is Caroline Schaevel on for Brian Singer. Just a couple of questions. So first, you've highlighted not just today, but previously that your expectation for second half of the year CapEx to be down versus the first half. And now that we're here, you're reiterating it. And can you just talk a little bit more specifically about what drivers are beyond the drop in rigs that you mentioned earlier, whether it's facilities, inflation, expectations, etcetera? Yes. Hi, Carolyn. You caught me off guard there when they announced you as Brian. But yes, no, thanks for your question on capital. I think we've outlined all through the year that our plan and through the year had a spending more capital in the first half than the second half. It was aligned with the growth pattern we had across the business. Mike talked some about this. Our 2Q capital was slightly higher than what we had planned because we actually drove longer laterals than we originally planned and had faster cycle times. But as we look to the rest of the year, I think we plan to execute the rest of the program And then really any discussion about capital really now focuses on 2019 and we're looking at that quite hard right now. Hey Doug, it is Brian. Actually we're tag teaming here. So appreciate the time. For our follow-up, you mentioned that at today's strip, Encana is going to generate free cash flow during 2018. If we look at the share buyback that you have, it seems to be characterized as more driven by some of the asset sales that you've done. So as Encana transitions to free cash flow, how do you think about the allocation there? And is increasing the buybacks something that would be under consideration? Yes, Brian. The STAG team and thing change in voice is going to get tough on me here. But the we've talked about this a number of times. We have the what we call the 3 buckets, which we think about is resiliency, which of course is trying to make the company stronger in a down market. So those are things like commitments and debt. We've talked about direct return to shareholders, which are buybacks and dividends. And then we've talked about reinvesting in the business. And we continue to talk about those things with the Board. And when we look at them, I think the one we have said is some of the resiliency measures given where our balance sheet is today don't look particularly attractive. Obviously, we're halfway through the buyback we announced. And I think as we tried to emphasize on the call, we are managing costs and driving very effectively. So we're turning margin, I mean price into margin and returns. And that as we've said all along is critical for us to demonstrate that before we'd consider adding additional capital to the business and growing even faster. I will tell you that Renee mentioned this, we have our regional price protection in the Permian between transport and basis hedges aligned with our 5 year plan. But one advantage we do have is obviously we have other assets in the portfolio to invest into like Eagle Ford and we're looking at all that. So it's a little early to say exactly what we'll do, but if we can continue to demonstrate that we can manage cost and drive efficiency, that will be an important driver. Great. Thank you from the best of us. Your next question comes from the line of Greg Pardy with RBC Capital Markets. Your line is open. Thanks. Good morning. Maybe just to dig in a little bit more into Pipestone and I'm wondering maybe if you could give us just a little bit more framework in terms of what drilling program is looking like this year because I think it's a pretty big CapEx number, right, almost $200,000,000 that you're spending there? Yes. Hi, Greg. I'll let Mike pick this up. I mean, one of the things to know and Mike kind of highlighted both at Cupp Anchorage and at Pipestone that we actually drill in and fill the facilities up over time. We don't try to have the well stock ready at startup. We don't think that's the best way to manage capital efficiency. Obviously, we brought the tower facility on well ahead of schedule and it was also under budget. The Pipestone facility is still tracking to early Q4. Costs are looking good there, but maybe Mike talk about the remainder of the year on drilling in Pipestone. Yes, you bet, Doug. So I mean, currently have a couple of rigs running right now in Pipestone and we'll kind of run at that level through to the end of the year. But we'll see kind of as Doug mentioned with the liquids hub coming on early Q4, we'll be ramping our production into that hedging. So, Renee did a great job in terms of running down how you approach things. I mean, the hedging. So Renee did a great job in terms of running down how you approach things. I mean, the hedging loss was kind of a fraction of what we were looking for. Could you enlighten me a little bit on why the numbers were so much better? Well, I think, Greg, we obviously talk about we guide and provide information annually. So it is a little hard to see it across the quarters. And part of that is that in some of these markets, we're a big enough player that if we talk publicly about what we were doing, we could potentially move those markets. So we have to be quite cautious in our disclosure there. But I would say it's a big focus. I mean, I think we're a little unique in that we consider managing fundamentals and markets one of the core four elements to deliver the most value in the business. And I think you just see that coming through. In particular, being out in front of market diversification, the benefit of being able to take Canadian gas to points like Dawn, have been very important in our transport to Houston, where we can then decide where we want to sell that crude. We've sold some of it off Brent pricing, some of it off Gulf Coast pricing. And next year, we'll have access to Corpus Christi as well pricing. I don't know if you have anything to add, Renee? I think for the most part you covered it, Doug. Okay. All right. Thanks very much. Your next question comes from the line of Gabe Daoud with JPMorgan. Your line is open. Hey, good morning, Doug and team. Maybe just a high level capital allocation question and you did hit on this Doug in the prepared remarks a little bit, but could you maybe just talk about the likelihood of incremental rig additions above the base plan for next year potentially going to the Eagle Ford versus the Permian and how you kind of shape the Permian program next year ahead of your Feet ramp. Could you maybe just talk a little bit about that? Yes. Gabe, yes, it's a great question. We're working that very hard right now. Clearly, we have additional transport volumes in 2019, both to Houston and effectively to Corpus. And but that's really tied back to our original 5 year plan. So one of the things we're looking at is we wouldn't want to add additional diffs when we have other options, like we have with the Eagle Ford. I mean, if you look at today's pricing, you're actually you would actually be getting at least $20 a barrel more off an Eagle Ford barrel versus a Permian barrel. So Mike and his team are working quite hard to see what can we do efficiently beyond current activity levels. And that's part of thinking about 2019 capital. But we don't want to grow barrels in the Permian that are unprotected at the current diff market, but we have other options in the portfolio. Great. That's helpful. Thanks, Doug. And then I'll try one more time on 2019 and your free cash flow profile. Obviously, the $500,000,000 estimate you guys have out there on a deck that's a bit stale. Could you maybe just give us a sense of what free cash flow could look like on 2019 on current pricing? Obviously, we could all kind of do the math ourselves. But just curious to hear your thoughts and then also incremental use of the free cash above the $500,000,000 Would it again, so that's a failure, but would it go towards more buybacks? You have some notes that are due next year? Is it for some debt reduction? Just anything there would be helpful. Yes. It's a little early to provide too much detail on 2019. Obviously, we're kicking off our budgeting process. But there'll be more and actually potentially a lot more cash flow next year, if you use kind of current strip pricing than we had in the original 5 year plan. But Sherry hit this pretty hard in her remarks, we're really focused on making sure that we convert price to margin and not let it go to cost. We're really pleased that year over year our costs are not up, they're down. We continue to drive our well performance and well costs in the right direction there as well. But this is critical to us. We don't just want to add activity to grow volume. We want to add if we add activity, it has to grow cash flow. So we have to demonstrate that. We're working that very hard right now and it's one of the things under consideration. I tried to cover earlier the buckets. The things like buying down long term debt doesn't look attractive today given where our balance sheet is. So it's highly unlikely that that competes well. But where shareholder returns versus reinvesting in the business compete, it's a bit early to make that call. Awesome. That's helpful. Thanks Doug. Your next question comes from the line of Jeffrey Campbell with Tuohy Brothers. Your line is open. Good morning and congratulations on the continued success. We've sort of been gravitating towards Eagle Ford here. So I just thought I'd ask for a little update here. Page 9, Slide 17 talks about stack pay and fill spacing and the Chalk as sources for premium location upside. You've already mentioned the Austin Chalk today. Could you provide a quick update if stack pay and infill drilling and infill spacing is being tested currently and maybe a little color if it is? Yes. Mike probably has some comments here. When we first started the Austin Chalk and it continues to be our approach. It's geologically more complex than the main Eagle Ford zone. So we've stepped into this carefully to make sure we'd have strong results across those investments. And so you've seen us slowly picking up the pace. On spacing, we started out at a 1,000 foot well spacing in the Chalk. We're now testing down at 500 feet. A bit early to make a call on that, but that's what we're looking at today. The other thing that's exciting in the Eagle Ford is an area we call the graben, which we currently don't carry premium inventory in, but we've now got several wells in there with our new high intensity completions, which are performing quite good. Mike, maybe you'd add some more color. Yes, you bet you, Doug. So with respect to the stacking question, we looked at sort of a 2 stack in the Eagle Ford and then 1 in the Austin Chalk. And we've got some really encouraging results in the Grubbin here of late, which gives us some confidence we can actually add to our premium inventory and that's in the Eagle Ford zone. So, yes, everything's looking really quite positive on the Eagle Ford with respect to our well results right now. I want to make sure that I understood correctly what you said there, Dan. Have you been doing this Eagle Ford Austin Chalk stacking and the Grubbin or have the encouraging Austin Chalk results in the graben stand on wells? No, no. We actually we do that we'll have a call it a 3 stack, 2 Eagle Ford and 1 Austin Chalk, but that's in the Panamaria area which would be to the southeast of the Graben. In the Graben, we're strictly just drilling Eagle Ford and it's a one so basically one stack. Okay, perfect. The other question I wanted to ask was about these Permian cube results. I was just wondering if you can quantify or qualify what's leading the outperformance that you've cited? And kind of what I'm thinking is the obvious Cube benefit is that the simultaneous completions avoid the parent child degradation and you guys have talked about that a lot. But it seems like the cubes are exceeding the production enhancement that avoiding degradation would imply. So I'm just wondering, is there something special going on in completions or does the cube lend itself to some outperformance in completions or is it could just be that the rock is better than you first estimated? Yes, Jeff. I think that you picked up on a really important point here that what we're showing is that if you do this take this cube approach, you get rid of the parent child effect, you really mitigate that problem. So what we're showing is with cubes, we're delivering some of the strongest wells in the Permian. But the recent jump is actually these high intensity completions we've been pumping now for about 9 months or so. So what we're showing and we will improve recovery because we're keeping the frac energy close to the wellbore. So what we're now seeing is high intensity completions combined with the cube are giving really strong results. Yes, just a little more color on that. We've tightened our cluster spacing from what we were doing sort of this time last year, basically putting in anywhere between 15 to 20 clusters per stage as well as increasing our sand concentrations up to about £2,000 per foot. So that's really helped drive the well performance that we're reporting this quarter. Along with that, we're using longer laterals wherever we can as well. And just a quick follow-up with regard to the sand is the fact that you're now sourcing so much of your sand locally, is that giving you a price advantage that's allowing you to stuff a little bit more sand in these wells or would that be justified anyway? Yes, Jeff. It is cutting our costs. We've talked a lot about this that it really takes out the rail piece of the sand cost, which as you know, the majority of the cost of sand is transport, not the sand itself. But that really the economics would work even without a basin sand, they're strong enough. It's one of the levers we're pulling to counteract inflation to keep cost in line despite the fact that the world's busier and we've got some inflation even though it's moderated quite a bit more recently. Okay, great. Thanks. I appreciate all the color. Your next question comes from the line of Geoffrey L'Anbuchal with Tudor, Pickering, Holt and Company. Your line is open. Good morning. Thanks for taking my questions. My first one is just on planning and maybe a near term outlook for some higher level items you're working on. You guys have stayed ahead of some of the biggest headline risks kind of across the board in both the Permian and Montney, especially related to service cost marketing, for example. I know there's been a big focus on the water hubs in the Permian recently. What are some of the things you're working on now that you see as out year headwinds that you're trying to get in front of today? Yes. Well, a lot of it, what's interesting is, you've got to always try to drive the car through the windshield and not the rearview mirror. And so instead of looking at what's happening right now recently, what are we anticipating to happen next? And clearly, with the differentials in the Permian, that's going to affect activity levels in the Permian, we believe, and we're thinking about how we manage the supply chain through that period. Renee spent a lot of time talking about how we try to integrate our view of markets and this isn't necessarily the macro, but the in basin markets and then how we actually maximize our value across the portfolio. So that's a big feature today of what we're trying to anticipate. Clearly, we're thinking pretty hard about what are the next things we can do to lower cost to offset other pressures which might try to increase cost. And Mike talked about in the Permian, 3rd party show us is by far the fastest driller in the basin at 12.5 days per well. We've got wells we've drilled at sub-nine and we're trying to figure out how do we get all of our wells to sub-nine instead of at 12.5. So we're pushing in all these areas. And I think one of the things we're trying very hard to do in the company is not let the mindset go to oil prices that are higher, but to say we have to create value through converting price to margin, and we have to do that through innovation, both technically and commercially. I'd also point to our recent deal with Keyera as another example of that, where we're creating flexibility and optionality in the business, which we're now seeing why that's valuable. And I know we've been committed to that even when it wasn't necessarily as popular, and I think we're demonstrating now why it adds value. Great, thanks. And then my follow ups on the design of Permian cubes. Just seeing if you can give any more detail on what to expect for I guess cube patterns in the back half of the year as it relates to targeting different horizons. Just trying to get a sense for other tests to watch for with maybe some context around the base design, if you will. Yes. Mike talked a little bit about this too. We're still tuning, if you will, the spacing and stacking. A lot of it now is how do we optimize given these new completion designs. But then when if you look at Martin County, where now we're proving that the Joe Mill is a commercial zone, we now have to think about how do we incorporate the Joe Mill into those cubes. And then actually, what do we do about coming back to areas where we didn't develop the Joe Mill in the early cubes. And I will say, if you go back a few years ago, the Joe Mill wasn't even a flash in our eye at that point. This is just showing why being in the core of the best plays really matters because they get better and these results are even actually going beyond what we expected. So it's really about fine tuning, spacing and stacking. It's also now about how do we incorporate new zones as we prove that they're commercial. Great. Thank you. Your next question comes from the line of Jason Fruh with Credit Suisse. Your line is open. Hi, Doug. I guess I'm hearing that the margin conditions exist in Eagle Ford for additional capital. I guess you've touched on it, but I guess I'm wondering to what extent your inventory is expanding sufficiently to warrant additional capital there? Thanks. Yes, Jason. It's kind of a in many ways Eagle Ford is a pretty cool story. When we entered, we said we would grow it to about 50,000 barrels a day, which we did. We also said when we entered the basin over 4 years ago now that we had about 400 wells to drill. 4 years later, we still say we have 400 wells to drill. And that's everything from down spacing to the Upper Eagle Ford to the Austin Chalk, and now the Graben. So we can't this asset clearly is not near the scale of either the Permian or the Montney, but we could do more in that asset, but we have to make sure we do it wisely and efficiently. It's not going to become 100,000 barrel a day asset, but it could grow beyond where we've had it in the past. And Mike and his team are working quite hard to make sure we can do that efficiently. We have 2 rigs there today. We've run as many as 4 at sometimes in the past and we're looking close at that for 2019. Thanks. That's great color. At this time, we have completed the question and