Good day, ladies and gentlemen, and thank you for standing by. Welcome to Encana Corporation's second 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 one. For members of the media attending in a listen-only mode today, you may quote statements made from any of the Encana representatives. Members of the media who wish to quote others who are speaking on this call today, we advise you to contact those individuals directly to obtain their consent. Please be advised that this conference call may not be recorded or rebroadcast without the express consent of Encana Corporation.
I would now like to turn the conference call over to Corey Code, Vice President of Investor Relations. Please go ahead, Mr. Code.
Thank you, operator, and welcome everyone to our second quarter 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. 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. Sherri Brillon, our CFO, will highlight our financial performance.
Reneé Zemljak, our EVP of Midstream Marketing and Fundamentals, will highlight the benefits of our marketing strategy, and Michael McAllister, our COO, will then describe our operational results. We will then open the call up for Q&As. We will now turn the call over to Doug Suttles.
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. 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 are 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 400,000 to 425,000 barrels oil equivalent per day in the fourth quarter. In the Montney, we delivered liquids growth of 18% over the first quarter, despite a planned turnaround at one of our facilities. We remain on track to achieve an average liquids rate of 55,000 to 65,000 barrels per day in the fourth quarter. 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 second quarter 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. We continue to grow liquids volumes and cash flow. We are very pleased with our results so far this year. 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 five 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 stack 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 five-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 risk 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 Encana a unique E&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 second quarter, 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 received went directly to our margin.
Second quarter cash flow margin was also positively impacted by tax and related interest recovery of $75 million. This contributed a $2.44 per BOE uplift to our second 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 second quarter cash flow of $586 million, 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 million versus a gain in the first quarter of $68 million 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 to execute our share buyback and have now completed half the program. We expect to complete the $400 million authorization by the end of the year. We are 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 2017. 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 million.
Adding to that upside is the stronger prices we are seeing this year, which helps further lift liquids revenue another $365 million. 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 is critical that we are able to manage costs even as prices rise. Our objective is to convert higher prices to higher margins and 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 2017.
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, Reneé will share an example from our Permian to highlight this strategy. Our increased liquids mix and strength in the benchmark price improves realized pricing. The key has been to continue our shift towards liquids production without expanding our cost structure, 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&P costs are up slightly due to our market diversification strategy.
In return for increased T&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 Reneé.
Thanks, Sherri. 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 this strong integration across the company that enables us to effectively mitigate regional price risk, including AECO gas and Permian oil dynamics. There are three main components to our approach to our commodity monetization. First, 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. Second 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 million for the second quarter and about $100 million 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 second 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 WTI 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, Reneé. Across the portfolio, our plan 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 second quarter, 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 de-risks our second half Montney liquids production ramp and has us firmly on track to achieve 55,000-65,000 barrels per day in Q4. As industry activity picks up in the busier basins like the Permian and Eagle Ford, we 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 Graben area and continued to develop the Austin Chalk. Early results are promising and are helping to de-risk future increases of our premium inventory. In the Duvernay, we had a successful quarter of drilling activity with new pace setter performance on extended reach laterals. To achieve the objective of delivering 30% growth, we laid out our 2018 program with our drilling and completions 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 four rigs, down from five in Q1. In the Montney, we currently have seven rigs running, down from 12. In the Eagle Ford, we started the year with three rigs and now have two operating today. We expect our 2018 Duvernay drilling program to be wrapped up, I should say, in the next couple of weeks and the completions activity to 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 second quarter 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 three new cubes in the second quarter in Midland and Martin Counties. The 10-well 2018 Martin cube that we highlighted on the Q1 call produced 1 million barrels of oil in its first 99 days. With almost six months of production, this cube is on track to exceed type curve IP 180 by over 50%. Three 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 four Martin County Jo Mill wells we brought on to date, we have seen IP 30 production of 1,100 barrels per day of oil. Results have been similar to what we would expect from a 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 pace setter in Q2, drilling over one mile of lateral in 24 hours. We consistently benchmark our performance against our peers. Our drilling performance continues to be industry leading. In a 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 three days faster than the next closest competitor and five and a half 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 seven interconnected water resource hubs that combine 6 million barrels of storage capacity. Recall that our water hubs are a simple catch basin design that only cost about $3 million 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% recycled water stages and expect to recycle over 25 million 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 second year in a row. In the second quarter, we grew liquids production by over 18% versus Q1. Our liquids growth trajectory has continued into the third 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 de-risks our ability to deliver between 55,000 to 65,000 barrels a day of liquids production from the Montney in the fourth 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 fourth quarter of this year and into 2019. In the second quarter, we successfully executed plant turnaround at our Sexsmith 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 million on the low end, to as high as 800 barrels per million 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, where 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 Sherri 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 55,000-65,000 barrels per day while deriving greatest value from our assets. Our 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 second quarter. We brought on 11 wells in Q2, including one new Austin Chalk well. Year to date, we have brought on one Eagle Ford well in the Graben area and five Austin Chalk wells. Our 2018 results in these areas are de-risking potential future premium inventory, and additional wells are planned for later this year. The average IP90 for the 2018 Austin Chalk wells is almost 1,350 BOE per day.
These wells are meeting our type curve expectations and delivering an after-tax rate of return of 100% at $50 WTI and $3 NYMEX. The Eagle Ford and the Duvernay continue to generate free operating cash flow in the second quarter, 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 fourth quarter of 2017 levels.
We expect production from the Duvernay to flatten out in the third quarter, and to see a return to growth in the fourth quarter similar to levels of Q4 2017. The Duvernay saw increased activity in the second quarter. In Simonette North, we achieved new pace-setter drilling performance. Our latest six wells in Simonette North are all over two-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 two-well pad in the volatile oil window in the quarter. We are very encouraged by the initial production results. The average IP30 of the two wells is about 1,050 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 de-risking our five-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 five-year plan even better. We are focused on growing value. Our disciplined capital allocation is tightly aligned with an informed perspective on 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, we'd now be happy to take your questions.
Ladies and gentlemen, as a reminder, you can join the queue to ask a question by pressing *1. We will now begin the question-and-answer session and go to the first caller. Brian Singer with Goldman Sachs, your line is open.
Hi, good morning. This is Caroline Shavel on for Brian Singer. Just a couple of questions. 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. 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, et cetera?
Hi, Caroline. You caught me off guard there when they announced you as Brian. Thanks for your question on capital. I think we've outlined all through the year that our plan through the year had us spending more capital in the first half than the second half. It was aligned with the growth pattern we had across the business, and 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. It had faster cycle times. As we look to the rest of the year, I think we plan to execute the rest of the program. 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. Appreciate the time. For our follow-up, you mentioned that at today's strip, Encana's going to generate free cash flow during 2018. If we look at the share buyback that you have-
Seems to be characterized as more driven by some of the asset sales that you've done. As Encana transitions to free cash flow, how do you think about the allocation there? Is increasing the buybacks something that would be under consideration?
Yeah, Brian. This tag teaming thing, changing voice is going to get tough on me here. We've talked about this a number of times. We have what we call the three buckets, which we think about as resiliency, which, of course, is trying to make the company stronger in a down market. 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. We continue to talk about those things with the board. 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 efficiency very effectively. We're turning price into margin and returns. 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, Reneé mentioned this, we have our regional price protection in the Permian between transport and basis hedges aligned with our five-year plan. One advantage we do have is, obviously, we have other assets in the portfolio to invest into, like the Eagle Ford, and we're looking at all that. 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'll be an important driver.
Great. Thank you from the both 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, I'm wondering maybe if you could give us just a little bit more framework in terms of what the drilling program is looking like this year, because I think it's a pretty big CapEx number, right? Almost $200 million that you're spending there.
Yeah. Hi, Greg. I'll let Mike pick this up. One of the things to know, Mike kind of highlighted both at Cutbank Ridge 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's still tracking to early Q4. Costs are looking good there. Maybe, Mike, talk about the remainder of the year on drilling in Pipestone.
Yeah. You bet, Doug. We currently have a couple of rigs running right now in Pipestone, we'll kind of run at that level through to the end of the year. We'll see, as Doug mentioned, with the liquids hub coming on early Q4, we'll be ramping our production into that capacity, not have it sitting there waiting for the plant to start up.
Okay, that's perfect. The second just comes back to the hedging. Reneé did a great job in terms of running down how you approach things. 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 guide and provide information annually, so it is a little hard to see it across the quarters. 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. We have to be quite cautious in our disclosure there. I will tell you it's a big focus. 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. I think you just see that coming through. In particular, being out in front on market diversification.
The benefit of being able to take Canadian gas to points like Dawn have been very important, and 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. Next year, we'll have access to Corpus Christi as well, pricing. I don't know if you have anything to add, Reneé?
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, you did hit on this, Doug, in the prepared remarks a little bit. 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 FT ramp? Could you maybe just talk a little bit about that?
Yeah. Gabe, yeah, 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. That's really tied back to our original five-year plan. One of the things we're looking at is we wouldn't want to add additional activity in the Permian that just grows barrels into big diffs when we have other options Like we have with the Eagle Ford. If you look at today's pricing, you would actually be getting at least $20 a barrel more off an Eagle Ford barrel versus a Permian barrel. Mike and his team are working quite hard to see what can we do efficiently beyond current activity levels. That's part of thinking about 2019 capital.
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. Then I'll try one more time on 2019 and your free cash flow profile. Obviously, the $500 million 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 do the math ourselves, but just curious to hear your thoughts, then also incremental use of the free cash above the $500 million. Again, it's not necessary, 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.
Yeah. It's a little early to provide too much detail on 2019. Obviously, we're kicking off our budgeting process. There'll be more, and actually, potentially a lot more cash flow next year if you use current strip pricing than we had in the original five-year plan. Sherri 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. This is critical to us. We don't just want to add activity to grow volume. If we add activity, it has to grow cash flow. 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 other 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. 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. Congratulations on the continued success. We've sort of been gravitating towards Eagle Ford here. I just thought I'd ask for a little update here. Page nine, slide 17 talks about stack pay, infill spacing, and the Austin 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 spacing is being tested currently, maybe a little color if it is?
Yeah. Mike probably has some comments here. When we first started the Austin Chalk, it continues to be our approach, it's geologically more complex than the main Eagle Ford zone. We've stepped into this carefully to make sure we'd have strong results across those investments. You've seen us slowly picking up the pace. On spacing, we started out at 1,000 foot well spacing in the Chalk. We're now testing down at 500 feet. A bit early to make the call on 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, 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.
Yeah. You bet you, Doug. With respect to the stacking question, we looked at sort of a two-stack in the Eagle Ford then one in the Austin Chalk. We've got some really encouraging results in the Graben here of late, which gives us some confidence we can actually add to our premium inventory, not in the Eagle Ford zone. Yeah, 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 at the end. Have you been doing this Eagle Ford, Austin Chalk stacking in the Graben, or have the encouraging Austin Chalk results in the Graben been standalone wells?
No. We do that, we'll have a, call it a three-stack, two Eagle Ford and one Austin Chalk, but that's in the Panna Maria area, which would be to the southeast of the Graben. In the Graben, we're strictly just drilling Eagle Ford, and it's basically one stack.
Okay.
Permian.
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. 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. It seems like the cubes are exceeding the production enhancement that avoiding degradation would imply. I'm just wondering, is there something special going on in completions, or does the cube lend itself to some outperformance in completions, or it could just be that the rock is better than you first estimated?
Yeah, Jeff. I think that you've picked up on a really important point here, that what we're showing is that if you take this cube approach, you get rid of the parent-child effect. You really mitigate that problem. What we're showing is with cubes, we're delivering some of the strongest wells in the Permian. The recent jump is actually these high-intensity completions we've been pumping now for about nine months or so. We actually think that those not only deliver stronger early well performance will improve recovery because we're keeping the frac energy close to the wellbore. What we're now seeing is high-intensity completions combined with the cube are giving really strong results.
Okay, great.
Just a little more color on that. We've tightened our cluster spacing from what we were doing this time last year. Basically putting in anywhere between 15-20 clusters per stage, as well as increasing our sand concentrations up to about 2,000 pounds per foot. 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.
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?
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. 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 Jeoffrey Lambujon with Tudor, Pickering, Holt & Co.. 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 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?
Yeah, well, what's interesting is you've got to always try to drive the car through the windshield and not the rearview mirror. Instead of looking at what's happening right now or recently, what are we anticipating to happen next? 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. Reneé 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. 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. Mike talked about in the Permian, third parties show us as by far the fastest driller in the basin at 12.5 days per well. We've got wells we've drilled at sub 9, and we're trying to figure out how do we get all of our wells to sub 9 instead of at 12.5. We're pushing in all these areas, 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 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. I know we've been committed to that even when it wasn't necessarily as popular, I think we're demonstrating now why it adds value.
Great, thanks. My follow-up's 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.
Yeah. Mike talked a little bit about this too, where 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. If you look at Martin County, where now we're proving that the Jo Mill is a commercial zone, we now have to think about how do we incorporate the Jo Mill into those cubes, actually, what do we do about coming back to areas where we didn't develop the Jo Mill in the early cubes? I will say, if you go back a few years ago, the Jo 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, these results are even actually going beyond what we expected.
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 Frew with Credit Suisse. Your line is open.
Hi, Doug. I guess I'm hearing that the margin conditions exist in the Eagle Ford for additional capital. 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.
Yeah. Jason, in many ways, Eagle Ford's 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 four years ago now, that we had about 400 wells to drill. Four 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. 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 two rigs there today. We've run as many as four at some times 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 answer session, and we'll turn the call back to Mr. Code.
Thanks, operator. This now concludes our Q2 call.