Ovintiv Inc. (OVV) Q2 2017 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and thank you for standing by. Welcome to the Encana Corporation's Second Quarter 2017 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. [Operator Instructions] 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 Brendan McCracken, Vice President of Investor Relations. Please go ahead, Mr. McCracken.

Thank you, Operator. Welcome everyone to our second quarter results conference call. This call is being webcast and the slides are available on our Web site 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, 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. Sherri Brillon, our CFO, will highlight our financial results. Then, Mike McAllister, our COO, will describe our operational highlights. And Reneé Zemljak, our EVP of Midstream Marketing and Fundamentals, will discuss our management or risk. We will then open the call up for Q&As. And I'll now turn the call over to Doug Suttles.

Thanks, Brendan, and good morning everyone, and thank you for joining our call. Q2 marks another very strong quarter of execution. Halfway through 2017, we are well ahead on the first year of our five-year plan. Our results highlight our ability to generate quality corporate returns through the commodity cycle. Our margin was up 25% from the first quarter despite lower benchmark commodity prices. This was driven by more oil and condensate in our production mix and lower cost. Our core assets have returned to growth, delivering our planned mid-year production bounce ahead of schedule. We continue to increase well productivity and portfolio, and as a result we now expect that the core assets will deliver 25% to 30% growth in the fourth quarter of 2017, when compared to the fourth quarter of 2016. Based on our strong year-to-date performance, we have increased production and lowered cost in our updated 2017 guidance. The rapid application of technical innovation across the company has been impressive, and has driven significant improvement in each of our programs. As a result, we have increased our type curve substantially, and expanded our total premium well inventory by 20%. For the third consecutive year we continue to strengthen our financial position. By year-end, we expect net debt to adjusted EBITDA to be approximately two times. The combination of innovative operations, commercial ingenuity, and preserving optionality is creating value and managing risk. I'll now turn the call over to Sherri, who will provide an overview of our financial results.

Thanks, Doug, and good morning everyone. Our strong second quarter results demonstrate that our business is working well at today's prices. Our cash flow, operating margin, and corporate margin all grew even though index prices were about 5% lower quarter-over-quarter. Our Q2 corporate margin was up 25% from Q1. This is a direct result of our improving product mix and continued cost reductions. On a consolidated basis our liquids mix in the quarter increased to 40% of total production. This is a significant step change from 35% in Q1. As Doug mentioned, during the quarter the core assets returned to growth ahead of schedule, with core liquids production growing by 15%. We now expect Q4 2017 production growth of the core assets to be between 25% to 30% versus Q4 2016. We had previously guided to growth of over 20%. This added growth continues to be focused on high-margin oil and condensate with expected growth of 35% to 40% Q4 2017 versus Q4 2016. Following the close Piceance sale, core asset production will dominate the portfolio at over 90% of total company production. With the Piceance sale and continued liquids growth we expect to be largely balanced between liquids and natural gas by year end. Mike is going to cover our significant well productivity improvements we've seen year-to-date, the result of this is an overall 10% improvement to our 2017 capital efficiency. To reflect the increased well productivity and an improved capital efficiency that we are seeing across the portfolio we have updated our 2017 guidance. We've also highlighted the impact of divestitures on our full-year numbers. Excluding the impact of the announced dispositions, we are increasing total production by 800 BOE per day, roughly evenly split between liquids and gas. Our capital guidance is unchanged as we have continued to be successful at more than offsetting inflation. The bottom line is that we're getting more production and cash flow for the same capital. We are also dropping our per unit T&P and operating cost guidance for the year, demonstrating our continued success in driving costs lower to enhance margins. Our expected annual cash flow and corporate margin are both tracking ahead of plan. The expected 2017 cash flow impact of our dispositions this year is roughly $100 million. This has now been more than offset in 2017 through production growth and cost efficiencies. The proceeds from the dispositions will reduce net debt. Following the close of the Piceance transaction our unutilized transportation costs associated with [Derrick's] [ph] pipeline will be reported in our marketing optimization segment. We now expect the market optimization segment to have an operating loss of about $25 million per quarter, up from about $15 million per quarter in the first half of the year. We have taken decisive steps to further strengthen our balance sheet and ensure we are positioned for continued success in a lower-for-longer price environment. We have reduced our total debt by $3 billion since year-end 2014 during some of the most challenging years in our industry's history. Our leverage ratios continue to drop, and by year end we expect our net debt to adjusted EBITDA to be approximately two times. We have significant financial flexibility in our debt structure, with no maturities until 2019, and three quarters of our long-term debt not due until 2030 and beyond. We also continue to have access to significant liquidity. By year-end, we expect to have access to over $5 billion of liquidity. We are committed to preserving the sustainability and financial strength of our business throughout market cycles. One of the key tenants of our five-year plan is that our capital program will be funded with cash flow. Our continued margin expansion and improved capital efficiency gives us confidence that we can deliver significant growth within cash flow at lower prices. Across the company our liquids growth and lower costs are driving margin expansion. Our margin's been boosted by our improved product mix, continued focus on reducing cost, and our hedges. In the second quarter, our liquids mix has jumped from 35% to 40%. This increase added $1.44 per BOE to our corporate margin in the quarter. Lower operating and corporate costs also drove the corporate margin higher by a combined $1.48 per BOE. Our hedges almost offset the impact of the drop in benchmark prices from Q1. The result is our corporate margin rose by 25% quarter-over-quarter. The margin expansion from our improving product mix will continue as we grow liquids and the cost reductions are sustainable going forward. As a result of this performance, we now expect we can deliver on the same corporate margin targets for this year, and our five-year plan at a lower oil price. When we rolled out our five-year plan last October, we said that we expected to achieve an $8 per BOE corporate margin this year at $55 WTI. In January, we revised this estimate to more than $10 per BOE, and we now expect to deliver close to $11 per BOE, at prices less than $50 WTI. I will now turn the call over to Mike.

Thanks, Sherri. The Montney is a key driver of our liquids growth. Our Montney liquids production has grown to 16,000 barrels per day in Q2. 80% of these liquids are condensate. Our realized prices for Canadian condensate this year have averaged 95% of WTI. In Q4 of 2016, our liquids mix in the Montney was 11%. Our 2017 drilling program has an average liquids mix of 35%. In Q2, total mix in the Montney has grown to 14%, with only 12 net wells on stream. The production growth associated with the startup of our Montney plans in Q4 will increase our liquids mix to 20%. We've drilled 41 net Montney wells so far this year, and now expect to have 65 net wells on stream by year-end. As Sherri just showed, this increasing liquids mix is expanding our margins both for the Montney and for the entire company. The Montney plants continue on track and on schedule to startup in the fourth quarter. Our well results continue to support our liquids growth plan. We have over a year of production from our most liquids rich areas of the play, and we have seen sustained liquids rates. The plot on the slide shows those liquids rates for a number of our Tower wells. These Tower wells are on track to produce 25% to 40% liquids over their full life. These results are a good example of our deep inventory of premium locations in the Montney. By Q4 this year, we are set to double our total liquids production from the Montney to over 30,000 barrels per day. This growth in high-value liquids production, combined with disciplined execution is directly contributing to Encana's corporate margin expansion. This year we have been successful at driving significant productivity improvements across our portfolio. We have taken a highly structured approach to understanding how to increase well productivity in unconventional rocks. We used innovation and technology to optimize our completion design and well targeting. One of the most important points is that these productivity gains are not coming from just pumping more water and sand. More sand and water can lead to better wells, but it also means higher costs. Year-over-year, we have modestly increased the amount of sand and water we are using, but we have dramatically tightened our cost of spacing to create more effective fractured networks. This has had the effect of improving well productivity without substantially increasing well costs. As a result of our well performance improvements, we boost that our Permian type curves by 20% back in June. Our type curve IP180 is now the highest of our peers in the Midland Basin. We continue to see that our approach to dense well development is adding incremental volume to our Permian acreage position. On our Q1 call, we shared the impressive results we were seeing in Eagle Ford and the Montney from our new completion designs. Based on those results, we are now announcing updates to our Montney and Eagle Ford type curves. Our Montney type curve have seen improvements of 20% to 30% in IP180. Our Eagle Ford type curves have increased by 45% in the Eagle Ford Zone and 15% in the Austin Chalk Zone on IP180 basis. Our latest completion designs from Duvernay are just coming on production. So, for now, those type curves are unchanged. The impact of increasing our type curves means our premium locations are more valuable, our business plan is more resilient than it was before. We now expect to be able to grow within cash flow at today strip prices, and these type curve improvements are a big part of why this is the case. Our type curve increases also mean we are converting more inventory into premium return category. Since we originally disclosed our premium return inventory last October, we have drilled 230 gross wells, we've replaced all 230 of those locations plus converted a further 1,790 locations for a total increase of 2,020 additions. This means for every well we plan to drill in 2017, we've added six locations to our premium inventory. At our Permian Investor Day, we announced increase of 700 locations in the Permian. Today we're increasing the Montney premium inventory by 1,000 locations. Importantly, the liquids mix of this inventory has once again shifted higher. The number of locations in the inventory has increased and the type curves are 25% higher. We continue to evaluate additional opportunities in Montney as we progress our completion designs. In the Eagle Ford, we are increasing the premium inventory by a further 40 locations. This is a combination of both Eagle Ford Zone and Austin Chalk. This is on top of the fifty Austin Chalk locations we added earlier this year. Similar to the Montney, the inventory has grown substantially, and the type curves are 15% to 45% higher. We are still testing additional opportunity in both the Graben area of the Eagle Ford and in the Austin Chalk. In the Duvernay, we've fully replaced all 30 locations we have drilled since October, and we are continuing to evaluate further opportunity from advanced completions in the Duvernay zone itself and in the Montney. Our development approach utilizes large multi-well pads, advanced completion designs, integrated infrastructure and detailed planning to maximize returns. In the Permian, we believe the best approach to development is to exploit as much of the stack as possible at one time. We call this developing the cube. The cube is aimed at getting at the most value at the highest returns from a stack pay resource. For 2017, well performance has been outstanding. Altogether we brought on stream 59 wells year-to-date. The average well performance of our 2017 program is running about 25% better than our 2016 average. Overall, these well results rank at the very top of the Midland Basin. These improvements have been driven by our completion designs and precision targeting. What's even more impressive is the majority of our 2017 program has been drilled using our cube development approach with denser well spacing than our competitors. We now have enough long-term data to be convinced that our dense well spacing is leading to true incremental recovery. We are also encouraged to see that cube - that each cube we have developed has outperformed our previous addition as we continue to progress our designs. The cube approach has benefits both above ground and below ground. We believe this is the best approach to maximize corporate returns. In stock reservoirs there is a clear benefit to drilling and completing the entire cube at once. We minimize the risk of communication with the pleated reservoir and avoid offset frac hits. Above ground, our approach is to developing the cube gives us significant cost and cycle time advantages. We can maximize efficiency and get higher utilization from our equipment crews and infrastructure. Our approach has established us as a leader in stacked pay unconventional rocks. I fully expect us to continue find new ways to tune our approach by embracing technology to cerate value. We are now able to operate a development scale in the Montney. And this impact is showing up in our cost and productivity. We are now seeing D&C cost under $3.5 million per well and well productivity increases that support a 25% increase in type curves. We've done a great of work understanding the rocks using our structured approach to maximize value. We rely heavily on data driven analytics to deliver better wells for the lowest capital expenditure. We use a variety of methods to physically map and interpret our reservoirs, evaluate well performance and model future opportunities. In Q2, we brought on a four well pad in South Dawson area with Montney. We also have averaged over 525 barrels per day of liquids and over 2600 BOE per day in the first 30 days. This production flows to the South Central Liquids hub, the first phase which came on in the second quarter. These well results are confirming our updated type curve expectations. As we continue to implement advanced completions designs across the Montney, we expect well performance to improve going forward. In the Montney, we have two cube developments underway currently. The north part of Tower acreage, we're getting ready to turn over to production with 28 wells in this cube. In the south part of Tower acreage, we are currently drilling 20 well cube development. All of these wells will flow to the new Montney plants which are on track for a Q4 2017 startup. We are continuously learning as we developed a play. And we expect our cube developments to approach -- to evolve over time. We are also focused on quickly deploying our learnings into subsequent well pads to optimize our well designs and increase productivity. Above ground just like the Permian, our approach developing the cube gives us significant cost advantages. We can maximize efficiency and get higher utilization from our equipment, crews, and infrastructure. This has led to our most recent pacesetter cost of under $3.5 million per well for 9000 feet laterals. We focus on innovation as a tool to continuously improve the advance completion concepts that we piloted in Eagle Ford less than one year ago has now been implemented in all four of core plays with tremendous success and continuous to evolve. In the Montney, our initial well results using titter cluster design are yielding at 3%-5% increase in condensate production in the first 180 days. In the Permian, we're just starting to see the results from our advance completions for the first three wells on production. In the first three days, these wells succeeded our type curves by 20%. Therefore, this is upside to the boosted type curves, we just updated a month ago. In all of our plays, we continue to push the envelope on our completion design by quickly implementing learnings and new technologies. However, completion design is not the only place the team is innovating. Across the organization, we're always looking for new ways to leverage technology and commercial ingenuity to create value. One example is our approach to water sourcing in the Permian. In June, we shared the details of our Howard County water solution. By using a third party, we reduced our upfront capital investment in exchange for area dedication. This approach makes sense for Howard County because there is less existing infrastructure which means more upfront capital would be required. By contrast in Midland Martin counties, we are self-building simple just-in-time water hubs to recycle our produced water and provide water for our completions. In 2017, we expect to use 25% recycled water in the Permian, which contributes to savings of about 300,000 per well and operating savings of about $0.80 per BOE. In Martin County, we expect to recycle 100% of our produced water for the remainder of the year. In the Montney, we have started to implement the early learnings of our full well fiber optic system. And we have started analyzing early production. The data is giving us further confidence that we are on the right track with our titter clusters. We also continue drive efficiencies through data analytics and automation. When our gas plants came on stream in the Montney later this year -- when they come on stream later in the Montney this year our team will control each facility with their iPads, which translates into lower costs and better operating performance. I will now turn the call over to Reneé. Reneé Zemljak: Thanks, Mike. With improved capital efficiency, higher margins, deeper premium inventory, and a more financial strength we have made the company significantly more valuable and more resilient through the first half of 2017. We are focused on continuing that trend through the second half and into 2018. We have been highly disciplined about managing risk and preserving our short-cycle capital advantage. Our capital program is 100% short-cycle. We have successfully managed the inflation pressure in the first half of this year with sophisticated supply chain management and efficiencies. One simple example is that we planned to ramp up rigs early. We did that back before year-end 2016, and we planned to ramp down rigs through the year. As part of that plan, we are now running 17 rigs, which is five rigs less than our peak rig count earlier in the year. This meant we are not out fighting to add services when the market was busiest. We also did not enter into long-term take-or-pay agreements where we could be at risk of being long capacity. We are keeping our capital program highly focused on drilling and completions, and avoiding expensive upfront investment by taking a just-in-time approach to our infrastructure solutions. On the midstream front, our arrangement with the Veresen Midstream in the Montney gives us a lot of flexibility at a very competitive rate. The startup of our Montney plants in Q4 will act to reduce our Canadian per-unit T&P, while adding higher margin production. Year-to-date, our Canadian T&P is $8.91 per BOE. Finally, as we have shared earlier, we have managed the market access risk in both the Montney and the Permian with the combination of physical sales arrangements, firm transportation, and active basin hedging. And now I'll turn the call back to Doug.

Thanks, Reneé. As you can see, we are now well ahead of year-one of our five-year plan. Our second quarter results are strong on every measure, margins, cost, capital efficiency, and productivity. We've raised guidance for the year and we'll enter 2018 even stronger. We've also further strengthened our balance sheet. We continue to capture efficiencies which when they're combined with supply chain management is enabling us to more than offset inflation. We have delivered substantial productivity improvements, and as a result we've boosted our type curves, and grown both the size and the value of our premium inventory. The combined effect of sustainably expanding our margins and getting even more production growth from the same capital means that as we look out into 2018 we are well positioned to make quality corporate returns and growth cash flow at prices similar to today's strip. We plan to do this while spending within cash flow. Thanks for listening to us so far this morning, and we'd be more than happy to take your questions. Operator, we're prepared to take the questions from Q&A at this time.

[Operator Instructions] Our first caller is from the line of Brian Singer with Goldman Sachs. Your line is now open.

Thank you, good morning.

Good morning, Brian.

You highlighted the capital efficiency and the improved EURs that are undoubtedly lower in your breakeven oil price. But given the interest in staying within cash flow for 2018, can you just talk a little bit more about how that involves depending on the commodity price to say what's good for now, and where you [technical difficulty] if at all [to connect] [ph] whether that would even be needed given the capital efficiency that you highlighted?

Yes, thanks Brian. I think we've talked some about this even back at the Permian day, but with the improvements we've made in well productivity in demonstrating that we can offset inflation, we now think that that plan that we announced in October of last year, which we talked about using a $55 TI price, a $3 NYMEX, and $1 equal basis, we could deliver -- we now think we can deliver that same plan at $5 less. And in fact, we can continue to grow within cash flow at prices below $50. Exactly where we'll position the company for '18, it's a bit early to decide, but the starting point for the frame is to grow within cash flow. But we do believe if you use, for instance, today's strip, that plan we showed you in October is probably still intact.

Great, thanks. And my follow-up is on the productivity gains side. You talked to cluster spacing and pursuit in targeting, you raised your EURs, but you also highlighted that there are a number of measures that you're testing particularly in places like the Duvernay and Montney. Can you talk about where are in the process of the productivity gains outside of lateral length improvement outside of increased sand usage, and sand intensity, and what, if anything, you would stress to drive productivity gains over the next year?

Yes, Mike's probably best place to pick that up, but I'll just start with one comment. Something we've been saying for a couple of years now is that we think it's more than just pumping more water and sand. In fact, the completion design itself is the best way to create value because you can make better wells without adding substantially to the cost of the well. And we've largely been doing that with what we call completions intensity. But Mike can pick that up.

Yes, absolutely, Doug. Hi there, Brian. What we're really trying to do is improve the fracture network near wellbore. And so with the tighter clusters we see that as one of the effects, and it's really showing up with improved productivity everywhere we've tested it. And going to continue to evolve that along with testing sand and what concentrations. The other I just wanted to mention is that we've gone strictly to thin fluids, either slick water or [high VSFR] [ph]. And we found that as being a real advantage as well.

Mike, is the scope for productivity gains over the next year similar to what you just raised your EURs by or is the scope more or less than that?

Sorry, Brian, I missed the very first part of that question, could you repeat it?

Sure. Is the scope for productivity gains over the next year similar to the percent change you just raised your EURs by or more or less? So what's the bogy here?

Well, yes, it feels like I'm now going to be negotiating Mike McAllister's targets for 2018. It's hard to know exactly, but we don't expect the productivity improvements to stop. We continue to push this. And as Mike even mentioned, we've just now brought on the first several wells with the new completion design in the Permian, and we're doing the same thing in the Duvernay. But I would expect our wells to continue to get stronger. Also, we're seeing the early benefits of cube style development which we've talked some about as well. It's a bit hard to predict exactly how much more improvement there'll be, but I'm pretty confident there will be more improvement.

Thank you very much, appreciate it.

Thanks, Brian.

Thank you. And our next question comes from the line of Greg Pardy with RBC Capital Markets. Your line is now open.

Thanks. Good morning. Doug, the increase from, I guess, over 20% to 25% to 30%, right, for the core four, how much of that is coming from the Eagle Ford, and can you give us an idea of just what's happening there? The rates really stood out in the quarter.

Yes, Greg, it's actually coming from across the portfolio. The Eagle Ford is doing quite well. And as Mike mentioned, in fact I think we talked about the last two quarters, that's where we really started piloting these very high intensity completions and have seen great results. And I think what you've seen; we've also added some inventory here. Part of it is in further delineating the Austin Chalk, and part of it is these stronger wells are pulling wells that were non-premium into the premium category. But for some time we've talked about the Eagle Ford being plus or minus a 50,000 barrel-a-day asset, which is still how we think of that. But what we've shown is those wells are highly productive. And we're then trying to balance out, making sure we don't overbuild facilities. So as we've also mentioned, we're basically drilling to fill existing facilities and minimizing new bills to maximize returns. So, I think the bigger strategic shape of the asset is largely the same, but it's actually getting a whole lot more efficient to get to that same outcome.

And it sounds like the facility's limitation would be about 50,000 then?

Plus or minus, and we're still working on that. I'll tell you, our team, because of these we're -- a lot of these wells we're drilling in the Eagle Ford payout in about 10 months now, so these are tremendous wells. And they're continuing to work to find ways to de-bottleneck or add new wells without having substantial new facility capital. And that's one of the things we're working on as look towards 2018 to see how much more of that we can do. I'd also mention, we started the year with three rigs in the Eagle Ford, we're at one today, and plus or minus expect to be there throughout the rest of the year.

Okay. Last one for me is just on the Davidson pad. So you'd brought another 19 wells there not that long ago. How many days in the quarter with those wells or the entire pad rather just sort of been on -- in back on in 2Q?

I don't know. But Mike, how about you, do you know?

I'd say that the pad would've been -- we started up in May. I don't have the exact date. So that's -- we can get back to you on the terms and specifics.

Okay, that works. Thanks a lot guys.

Thanks, Greg.

Thank you. And our next question comes from the line of Gabe Daoud with JPMorgan. Your line is now open.

Hi, good morning everyone. Appreciate the color so far. I guess maybe Doug, going back to the question on '18. Is it possible to maybe just get a little bit more specifics on your thoughts heading into next year? Just trying to figure out how we should think about the type of growth from the core four that's achievable next year within cash flow, and then how the rig count and spending shakeout in that kind of scenario?

Yes, just take you back to what we talked about in October, which was that in 2018 we could see a 30% expansion of our margins at fixed prices and a 30% growth. And of course, with the trends we're seeing today we're performing even stronger than what we talked about then. It's a bit early to put the details in, but I think that that's well within our sights today, and of course we're constantly trying to figure out how to improve that. Because, as we highlighted on this call, our margin is ahead of plan, and our exit production rate is ahead of plan as well. So we feel pretty confident about that. And as you know, the current strip isn't much different than what we've been seeing recently.

Okay, fair enough. And then just cost control, and LOE, really nice results there this quarter. Can you just maybe talk a little bit about the specifics behind that, and how you were able to achieve the nice sequential decline on a per-unit basis, I guess especially considering the BOEs are essentially kind of flat quarter-over-quarter, just anything specific there to highlight?

You may recall, back in 2015, we initiated a LOE cost reduction initiative, and take significant costs out of our operating LOE across the board. We're seeing big savings on water handling in the Permian has had a big impact. But as an example, in the Montney rate now there's 170 initiatives we're working on to drop our operating costs. So it's relentless pursuit of efficiencies.

Yes, Gabe, the only think I'd add to Mike's comments there is it really isn't one single item. It's kind of relentless focus on finding a way to do everything better. I mean, we've been pretty successful at reducing well repairs, which are a big driver of your operating cost. We've talked about recycled [indiscernible] water saving us money here. We're also working very hard about how do we continue to grow our production base without seen a commensurate growth in headcount. And Mike talked about use of automation and things like even iPads are helping us do that. But it really is almost thousands of individual efforts which are driving to this outcome. The other thing I'd just mention is, I think Reneé touched on it briefly, is that things like our [indiscernible] arrangement are actually going to reduce our plant cost in the Montney, as opposed to take them up, so that creative arrangement. And even that Howard County water deal that Mike mentioned, it actually is lower water handling cost than we saw today in our operations. So it's a lot of efforts that are driving to this outcome.

Got you. Thanks, Doug, thanks everyone. That's all I had. Nice quarter.

Thanks, Gabe.

Thank you. And our next question comes from the line of Jason Frew with Credit Suisse. Your line is now open.

Hi, Doug. I'm just wondering if you had any comments on the San Juan, I know you're assessing the play and how it may or may not compete for capital, I just wondered if there is any update on that play at this point? Thanks.

Yes. Hi, Jason, thanks for the question. If you remember, the plan was to drill six wells. And then we thought by the end of this year we would probably have enough production information to hopefully confirm our understanding of the geology and what we think the play could do. We've got four to six online now. The fifth is -- wells have been drilled and the sixth is drilling as we speak, the Tosoto wells are performing actually above type curve in their first kind of six weeks or so. So we are encouraged by the early results, but I do think we want to make sure we have a bit of time on the clock on those. I still think we're on track to have good information to make decisions by the end of the year.

Okay, thank you.

Thank you. And our next question comes from the line of Josh Silverstein with Wolfe Research. Your line is now open.

Hi, good morning guys, and thanks for the comments on the 2018 outlook there, I was just curious if you guys are looking to keep spending within cash flow and as of right now having roughly $400 million of cash in the balance sheet plus another $700 million or so committed, what are you guys looking to do with that cash balance does it go into the ground, does it go to acquisitions, debt reductions any thoughts there?

Yes, Josh, I think at the moment and of course we all know we are still in July and the environment is relatively volatile but what we said for the time being is that the proceeds specifically from the PR sales would go to the balance sheet and then what we're able to do then starting next year which is the original plan is grow within cash flow, so that's where as we sit today and how we think about the world.

Got it. Okay, no plans to why I guess no plans to just put it right towards the balance sheet right now but it's there for you guys, in case these opportunities does further accelerate our acquisition opportunities just being flexible right now?

Yes, it's just about flexibility. As I said we're not as we sit here today thinking we'll use those proceeds to fund our capital program, we would do that from cash flow having a bit of flexibility in this environment is nice but we also don't have big acquisition plans either at the time being.

Got it. Thanks and then just on the key development I'm curious how you guys are looking at the balance of capital and the number of wells and then the timing of one production comes online does that seem to be a right mix of we need to have 14 wells drilled or is it just based on the units that you guys have like how many wells go into a certain direction.

It's really excuse me it's really driven by how to get the optimum development of the resource most efficiently what's interacting with that is the stack is still getting de-risk in the Permian both up and downhole, and so that comes into play as well, but what we're finding is these large multi-well pads are more efficient on the surface. Our capital costs are lower and they're more efficient at recovery on the subsurface as well. So it's really how best across our acreage to actually maximize those two things are there, there is no precise number per location because also the stack is a different in different areas. And now that we're at the scale we're at today there isn't really any significant lumpiness in our production profile because of this where we've kind of been in almost steady state mode if you will keep development for several quarters.

Got it. One last quick one for me on two Montney pilots of the 20 and 28 well spacing units is that upside to the Permian inventory or is that what you guys are anticipating right now.

Well, I wouldn't call a pilots I think this is our development model in the Montney in, I think what you saw even in this call is our Permian inventory has been expanded and I think if Mike, I don't you probably picked up on the well cost me $3.5 million in fact I think our best well as at 3.3 what that will tend to do with those kind of efficiencies is bring additional inventory into the premium category I mean the capital intensity to reach our targets there essentially fill up those plans will be even better.

All right. Thanks guys.

Thank you. And our next question comes from line of Bob Morris with Citi. Your line is now open.

Good morning, Doug. Congratulations on the nice quarter. On the testing the higher intensity completions obviously you've gotten to the extreme end of the second versus a lot of your peers have been going to the cube and the tighter cluster pacing. And it's always easier to benchmark or test completion methodologies drilling a single well at a time and then seeing how that compares with the prior well. But in drilling these big cubes or pads, how are you approaching continuing the test and optimize the completion? Are you varying the completion designs within the cube or pad itself across the wells, or is it just that you test one completion design for all those wells in the cube or pad. And then, wait the time you need to see that and then go and test the different methodology in the next pad or cube? Because obviously, it takes longer if you are doing it in batches like that rather than comparing single wells that a lot of your competitors to do.

Yes, Bob, we're actually trying and involving the completion design within the cube. So, it's not the completion design is fixed for each cube. And in fact, we're actually -- we're in completion design along the wellbore. I think we talked about that the fiber optic cable we laid in the Montney well where we actually tried multiple different completion designs in various stages because in that well, we can actually measure and monitor the performance differences by trying that. So, I think that this allows -- excuse me, this allows us to innovate in real-time on completion design and evolve quite rapidly.

Okay, that's good. So you don't have to wait for the next cube evaluating within the single cube by well in the meantime. So that's good, okay.

Yes.

Okay, that helps. Thank you.

Thanks, Bob.

Thank you.

Thank you. And our next question comes from the line of Brian Bagnell with Macquarie. Your line is now open.

Good morning, guys. So my question is on the Montney. There is a big budget growth coming on for you guys with the new facility in the fourth quarter. Just wondering if you can give an update on how much production you think you will be putting through that facility once it comes on? And how long do you think it will take to fill?

Yes, so the plan -- and I'll guide you back to our corporate deck which online which has the capacity of each one of those three plans. And as a reminder, two are coming on in 4Q. And the third is coming on in 1Q. We don't actually fill those completely according to our plan until basically late 2018. We're on track to do that. And of course, if we have stronger well, potentially there is some upside there. But what the plan is today is they don't start full, but they get full over between now and the end of 2018.

Okay, thanks. And just a follow-up on G&A, it looks like it was quite a bit lower in the quarter than usual, but no change to guidance. Just wondering maybe, Sherri, if you have any color on that?

Excuse me. No problem. It was basically as a result of the tax recovery and the interest related to that. And so, we had lower LTI cost. But in June we also -- we were able to have 17 million lower interest expense related to that that was part of the CRA assessment on previous year's audit.

Okay. Thanks, guys.

Thank you. And our next question comes from the line of Amir Arif with Cormark Securities. Your line is now open.

Thanks. Good morning, guys. I know you are still evolving the cube development, but in the Permian you started off with 12, 15, 19 wells in the cube. In the Montney, you are the 20, 28. Is that simply reflection of the lower well costs in the Montney, or are you just moving the large cubes as you go forward here?

Yes. No, it's a good question, but it actually really is about what's the optimum footprint both on the surface and subsurface. So you are going to see a range that won't all be the same size. What we do find is we particularly on the surface where we can use multiple rigs simultaneously on a pad and multiple frac spread, we get the best efficiencies. We get the lowest cost. But then you have to then combine that with what does the subsurface look like and also how you manage your facility. So, I think you are going to see a range even as low as eight wells and obviously as high as in fact we think that Davidson pad will probably exceed 60 before we are done.

Okay. And then just on the Montney pad specifically, you are testing a deeper Montney zone there. It seems like Montney D, and then you also tested the seismic, can you give us a sense of how many benches you feel are commercially developable in the Tower? And what kind of overall pacing you have tested with the recent two cubes?

I think what we will probably do if we could is I'll get Brendan and his team to follow-up with you. If you go to the Montney slide, it gives you some idea. But the number of benches you have varies across the play where you actually sit because you know that play is quite extensive. But if we could, we will just follow-up with you after the call.

Sure. That sounds good. And then just one final question on the Duvernay and I know you are testing the dissolvable plugs and trying to improve the drilling days. Can you give us an update on the average D&C well cost that you are seeing today in the Duvernay?

Yes. Basically it's staying the same, you know, in the north we are still in that $7 million range, so it's consistent with what we would have been reporting earlier.

Yes, just as a reminder, we've actually completed our Duvernay drilling program for 2017. We're just now bringing on some of the last of the completions. But I think if my memory serves me right, in the north it's about $7 million. And in the south which is deep and higher pressure, it's more in the $9 million range.

Yes, that's correct.

Okay. Sounds great, thank you.

Thank you. And our next question comes from the line of Jeffrey Campbell with Tuohy Brothers. Your line is now open.

Good morning and congratulations on the quarter. My first question was the press release mention developing new benches in the Permian, I was just wondering if had a color with regard to what you are thinking about there?

Yes, it does vary depending on where you are. But if you look at what we have been doing, if you go up into the Martin County, for instance, we have been testing the Middle Spraberry and even the Joe Mill. As we go further south actually what's happening there is we've now got a couple of wells into the Wolfcamp C, which we are testing. And we are also looking very carefully at the middle Spraberry. So it varies a little bit, but essentially the way -- best way to think about this is we're expanding both up and down from the lower Spraberry and the Wolfcamp A and B zones, which have been the primary targets for awhile now.

And I guess presumably if these tests continue to be successful than that means additional zones for the cubes in those areas?

Yes, that's exactly right. And we do think that this is part of the reoccupation strategy. And then, you can imagine, for instance, if you think about the Davidson pad, it's really half of a section width. This is how it is. So, we come to the other half, the cube that time around may include more zones right at the beginning. That's how we expect. And that's why we know if you will -– some people call it mow the grass in one part of the -- of our acreage all at one time because you continue to learn. And we're also learning from some of our offside operators who are testing additional zones as well.

Okay. Yes, it's good color. On the call today, you highlighted denser cluster spacing as an explanation for the 180-day type curve improvement that we are kind of seen across the board. I am just wondering there is increased lateral length also in meaningful variable in this improvement or have you largely standardized on your lateral lengths?

Well, what we do when we talk about a type curve is we normalize it back to our type curve laterally which you'll find though is we're trying wherever we can to drill 10,000 for laterals. We are being a bit cautious about going more than 10,000 feet. And the reason is just the confidence you have in getting a good completion or managing any trouble once you get beyond 10,000. We will probably get there as an industry, but today we don't think the risk is justified. But we do drill the longest laterals we can up to 10,000 feet. But the results we are seeing normalized back, for instance in the Permian to 7500 foot laterals.

Okay. Yes, that's helpful. And my last question is I was just wondering I am thinking about the cube. This Eagle Ford or perhaps portions of the Eagle Ford has a potential to benefit from the cube approach, or is there a minimum number of zones that you really need to make this work?

Yes, the -- one of the differences in the Eagle Ford is you don't have the same stack pay. But we have if you look -- look back how we've now developed an Eagle Ford section. So what we are thinking about there is the lower Eagle Ford, the Upper Eagle Ford and the Chalk. And we do the vine racking -- the play is a bit more mature. And it's one of these classics if you could wind the clock back, you'll probably do it a bit different than it was done today, but it's really a bit different in the terms of what the opportunity is there, but we have some areas which are pure Greenfield which we are -- you could call it a version of the cube, where we vine rack the Lower and Upper Eagle Ford in places where the Chalk is going to be productive, then we have the development scheme there. And then what we are doing there though, because much of that acreage already has facilities on it, we are now trying to do minimize new facility build to maximize returns.

Right. Yes, you mentioned that earlier in the call. Okay, that was great color. Thank you, I appreciate it.

You bet.

Thank you. At this time, we have completed the question-and-answer session, and return the call back to Mr. McCracken.

Thank you. This now concludes our call today. Thanks very much for joining us.