Ovintiv Inc

NYSE:OVV

Earnings Call Transcript 2018-Q1

[Operator]

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Encana Corporation's first quarter results conference call. As a reminder, today's call is being recorded. [Operator Instructions]

Please be advised that this conference call may not be recorded or rebroadcast without the expressed consent of Encana Corporation. I would now like to turn the conference call over to Corey Code, Vice President of Investor Relations. Please go ahead, Mr. Code.

[Corey Code, executive]

Thank you, operator, and welcome, everyone, to our first quarter 2018 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 your -- our webcast slides. Further advisory information is contained in our annual reports and other disclosure documents filed on SEDAR and EDGAR. Please note that Encana prepares its financial statements in accordance with U.S. GAAP and 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; Mike McAllister, our COO, will then describe our operational results; Sherri Brillon, our CFO, will highlight our financial performance; and then Renee Zemljak, our EVP of Midstream Marketing and Fundamentals, will reinforce our commercial mindset and our approach to marketing and risk. We'll then open the call up for Q&As. I'll now turn the call over to Doug Suttles.

[Douglas Suttles, executive]

Thanks, Corey, good morning, everyone. Thank you for joining us. Q1 was another quarter of strong execution. We are right on track to achieve our objective of growing overall production by more than 30% for 2018 while spending within cash flow. This puts us on a trajectory to deliver core asset production in the fourth quarter between 400,000 and 425,000 barrels a day. This is remarkable to be talking about core production exceeding 400,000 barrels per day when we were producing less than 240,000 barrels a day only one year ago.

Our quarter was critical in keeping us on pace to deliver the growing cash flow and volumes for 2018 and beyond. Drilling activity across the portfolio was significant in the quarter. We continue the efficient cube development operations in the Permian, with the backdrop of increased industry activity, while continuing to offset supply chain pressures. In the Montney, we continued an active drilling program with almost double last year's first quarter activity as we build liquids volumes in the facility capacity.

We ramped up drilling in both the Eagle Ford and Duvernay to deliver additional cash flow as those assets saw limited activity in the latter part of last year. Our cash flow continues to grow through a combination of increased liquids mix and cost control. This means that higher commodity prices translate into higher margin in returns. Our cube development approach continues to show tremendous results when combined with advances in completion design and operational efficiencies. We are seeing excellent cube results in the Montney with recent cubes averaging 300 barrels per day of condensate per well. Our Permian cubes also continued to demonstrate strong results. Mike will show you some of our results in Midland and Martin counties and how productivity continues to progress over time.

Importantly, we will also spend time this morning discussing the commercial mindset that we rely on to manage both commodity in basin-specific risk and maximize realized pricing. We saw this approach pay off in our Canadian business this quarter, as we successfully mitigated AECO price exposure and achieved a realized price almost equivalent to the NYMEX benchmark. We are also well positioned in the Permian, with virtually no exposure to Midland differential pricing this year and very little next year.

All of this is building a business, which generates quality returns through the commodity cycle.

Our Montney and Permian assets continue to grow in the first quarter, even after achieving significant growth in the fourth quarter of last year. As expected, our Eagle Ford in Duvernay assets declined from the fourth quarter of 2017. This was due to the shape of our 2017 drilling programs, which were front-end loaded. We have some terrific new well results across the portfolio that Mike will provide more details a bit later in the call.

We are on track to spend about $1.8 billion to $1.9 billion in 2018. Our capital program will be fully funded within cash flow. With higher activity levels in the first and second quarters, we are investing a slightly higher proportion of our capital program in the first half of the year. We are confident that we will deliver on our annual guidance targets. We expect total production to grow by more than 30% adjusted for the impact dispositions. Our fourth quarter core asset production target of 400,000 to 425,000 barrels of oil equivalent per day also represents more than 30% growth over the fourth quarter of last year. Our production profile in 2018 is expected to follow a similar trajectory to last year, as we expect to deliver significant growth in the third and fourth quarters. As you can see on the chart, we have been accelerating growth each 6-month period dating back to the end of 2016. While growth is not always ratable quarter-over-quarter, we had demonstrated a track record of consistent execution over time, and we expect this to continue.

Encana has been developing unconventional resources for over a decade and is one of only 3 companies who drill more than 5,000 horizontal wells. This long history means we have been drilling multi-well pads for many years and optimizing the logistics above ground. As an example, we have drilled pads as large as 64 wells in one of our legacy assets. This level of development created a culture and organization that understands the logistics required to operate very large pads safely and with competitive cycle times. The cube is our framework to maximize the value from our portfolio of resource plays. It is an evolution of the multi-well pad design that we've used in other plays. The cube is the way of thinking about the recovery of the resource in 3 dimensions, really in 4 dimensions, as you consider time. It is well accepted that the IRR of individual wells is higher with less density -- less dense developments. If Encana wanted to maximize only the IRR of an individual well, we would drill and complete wells with unbounded inner-well spacing, say, of approximately 1,000 feet. This would deliver the highest individual well return as we would ensure there was no interference between wells. However, this would not maximize the value of our resource. This [ could strain ] resource and result in significant lost value.

It is also well accepted that, at some point, this center well step spacing becomes too tight. Many factors could impact well spacing. We have been testing this since 2004 -- 2014. We also know that the formula is different in different zones and in different areas. So for this spacing discussion -- as I only mentioned a single zone and a resource play with multiple potential target zones, like the Midland basin. We must evaluate the optimum development strategy, both vertically and horizontally, to maximize the value of our land. This means considering the overlap of the fracture networks both within a zone as well as with the zones above and below. In the Midland basin, there is many as 6 zones being developed by industry right now, with a number of other zones being actively tested. This is where we use the cube approach to determine the best well spacing, stacking and completion design to maximize the full value of the cube rather than just chasing the best single well rates of return.

Managing for value means that we are deliberate about which zones are drilled in a single occupation. We consider the impact of development on both the current and future well returns. This is the heart of the much talked about parent-child relationship. And of course, all of this gets the benefits from the capital efficiency and productivity gains we get with the multi-well pads.

Our approach to cube development will continue to evolve to reflect changes in what we know, new technologies and innovation in completion design. Our culture of innovation means we are always learning from both our own data and that of our competitors. Our multi-basin advantage means that we are able to rapidly transfer learnings between the plays in which we operate to continue to make the cube even better.

[Renee Zemljak, executive]

Thanks, Doug. We've had a great start to 2018, carrying our momentum coming out of Q4. Our plan is well on track to deliver 30% production growth within cash flow. Our margin will continue to expand, with further liquids growth in the Montney and strong operating performance. We remain focused on operating efficiently to ensure that price improvements translate directly to our margin.

We have ramped up our activity across the portfolio, and our teams continue to innovate to deliver even more value from the cube.

In the Permian, our plan will deliver 30% annualized growth and 10% growth from Q4 2017 to Q4 2018. We expect growth in the Permian to be weighted to the back half of the year.

In Q2, we're anticipating modest growth because of offset frac mitigation. In the first quarter, our strong operational performance fully offset production declines, and we successfully mitigated weather-related interruptions. We remain focused on executing efficiently and at scale. Concurrent operations, like utilizing 4 service rigs at the same time, keep cycle time short and cost low by allowing us to share services on location. Our cube development approach and high-intensity completions continue to deliver strong well results and value from our stacked pay reservoirs.

Our cube approach delivers continued operational efficiencies beyond drilling and completions. Our centralized approach allows us to share facilities and water infrastructure to streamline operations. This has reduced our horizontal LOE to $2.50 per BOE in the first quarter.

Our supply chain management strategy continues to differentiate us as a superior Permian operator. We are well positioned to offset service cost inflation through sourcing efficiencies. Our approach to decoupling supply chain and self sourcing our commodities gave us a significant advantage this quarter. We utilized 40% local sand in Q1 and are on track to be utilizing 100% local sand by year-end. This represents a significant cost savings going forward. With delays in new mines coming on in the industry shifting to local supply, there has been some tightness in the sand market this quarter. We were able to leverage our existing relationships and suppliers to maintain a reliable sand supply during the quarter. In fact, the team did such a good job, we were able to sell some sand to a service provider.

Our proactive approach to securing midstream takeaway means that we are very well positioned with flow assurance for both oil and gas. We are also well protected from any basis differential weakness for both Midland and Waha. Renee will speak more about our differentiated approach to midstream and marketing shortly.

Our focus continues to be on structured innovation of the cube. This year, we will test new spacing and stacking configurations that implement our learnings from 2017. We will incorporate upside zones into our cubes to deliver more value from our stacked pay reservoirs. This will include the Jo Mill in Martin County and the Middle Spraberry and Wolfcamp C in Midland. Over 60% of our 2018 program will be on pads with more than 8 wells.

In Martin County, we brought on a 10-well cube during the quarter. With about 90 days of production, we have been really pleased with the results, which are significantly stronger than the 10-well cube we brought on in Martin last year. This is a great example of how we integrate our cube development approach, with advanced completions to continue to improve our results. Between 2016 and 2017, we advanced our reservoir targeting and increased our completion intensity. This year, our completion design incorporated our learnings from 2017, where we have taken up cluster spacing even further. Average IP90 oil rates from our lightest -- our latest Martin cube are 1,000 barrels per day and are on track to exceed our Martin type curve. Over the first 90 days, we have increased productivity by 70% in just 2 years.

In Midland County, we recently brought on an 8-well cube. Initial results are looking very promising. With about 30 days of flow, we're seeing initial rates of 1,500 BOE per day, with 1,150 barrels being oil. At the core of our cube development approach is a relentless focus on operating and capital efficiency. Our efforts to make our acreage position more contiguous are paying off. We expect the average lateral length in our 2018 program to be about 9,000 feet, an increase of about 15% from 2017. This makes well level returns for our Permian assets even stronger. Our base in leading rig efficiency means that we're adding more production per rig than our competitors.

We're running 5 rigs compared to similar sized competitors that are running around 8 to 10 rigs, while growing at similar rate. Our cube-style development means fewer rig moves and reduced exposure to supply chain risks. Our high-intensity completions deliver more productivity per well.

Our plan is on track in the Montney to double our liquids production from Q4 2017 to Q4 2018 between 55,000 to 65,000 barrels per day. We have seen strong condensate yields from the cubes that came in on the -- that came in the first quarter. This continues to give us confidence in our growth plans for the year.

Our infrastructure solution is in place. The third-party plans that were brought on stream late last year are running very well and averaged over of 98% runtime in the quarter. We will continue to ramp up into these facilities over the course of 2018. We expect to see consecutive quarters of liquids growth for the rest of the year. The largest steps of growth will occur in the back half of the year to coincide with the start up of the Tower and Pipestone liquids hubs. We have a turnaround scheduled at one of our legacy facilities, which is expected to have a 5,000 BOE per day impact in the second quarter.

By the fourth quarter, we expect to average between 55,000 to 65,000 barrels a day of liquids and well over 1 BCF per day of gas production.

A few weeks ago, we announced the Pipestone processing facility agreement with Keyera. This marks a significant milestone for our Montney development, providing certainty for facility infrastructure required to execute on our 5-year plan. The agreement includes the Pipestone liquids hub, which will add 10,500 barrels per day of incremental condensate capacity and is scheduled to come on stream in Q4. The deal also includes the Pipestone processing facility, a new sour gas processing plant with significant liquids' capacity. The facility is scheduled to come on stream in 2021. The plant will add over 19,000 barrels per day of net condensate and $150 million of net gas sales capacity in the Pipestone. This is another example of our commitment to capital discipline and strongly supports our focus on liquids-rich development in the Montney.

In Pipestone, our Q1 activity was dominated by drilling. We trialed a new monobore well design this quarter, delivering a pace-setter drilling time. We expect this new well design to save about [ $400,000 ] per well and reduce drilling days by over 20%.

The first quarter was a busy one for us in the Montney. We started the year running 13 rigs in the play and dropped down to 10 rigs through the quarter. We averaged 3 frac crews with a peak of 6 crews in Q1. We brought 5 cubes online in central Tower during the second half of the quarter. These cubes ranged from 6 to 14 wells in size. The cubes span the full range of our liquids windows and tower from gas condensate to very rich gas condensate.

While results from the 5 cubes have averaged 300 barrels per day of condensate and less than 5 million of -- million per day of gas in the first 30 days. In the richest benches, we've seen a number of wells with sustained condensate rates over 500 barrels per day. Wells in the latest Tower cubes have a type curve IRR between 80% and 140%. These economics are before the benefit of the joint venture carry at $50 WTI, $3 NYMEX and $1.50 AECO. This is why we remain focused on liquids-rich Montney development.

We continue to test our advanced completion designs in our latest cubes and included tests as tight as 10-foot cluster spacing in the richest part of the reservoir. Early results are encouraging, and we continue to incorporate these learnings in the remainder of our 2018 program.

The Eagle Ford and Duvernay are on track to generate significant free operating cash flow this year. We like these assets as part of our portfolio because they generate strong margin and free operating cash flow, while maintaining flat production. In the Eagle Ford and Duvernay, our activity levels ramped up over the first quarter. We ran 3 rigs in the Eagle Ford for the most of Q1, recently dropping down to 2 rigs, and we are currently running 4 rigs in the Duvernay and expect this to represent the peak rig activity for the year.

The production profile in the first half of this year is reflective of the pace of our 2017 program. In the Eagle Ford, we started 2017 with 3 rigs and ended the year with 1. In the Duvernay, our drilling activity was wrapped up by midyear, and all of our wells came on production in the third quarter of 2017. We realized record production volumes in both assets in the second half of last year, with the Eagle Ford producing almost 52,000 BOE per day in Q3 and the Duvernay producing 23,000 BOE per day in Q4. As a result of this, we realized a decline of volumes from Q4 2017 to Q1 2018. We expect to see further decline in Q2 and return to growth in Q3 as the majority of our 2018 program comes online.

Overall, we expect our combined 2018 annualized production from Eagle Ford and Duvernay to be similar to our 2017 average.

In the Eagle Ford, we brought online 2 Austin Chalk wells this quarter. Early results have been encouraging, with average production rates of over 1,900 BOE per day in the first 30 days. 70% of those volumes are oil. We expect about 40% of our 2018 Eagle Ford program to be in the Austin Chalk.

We continue to unlock additional upside on Eagle Ford acreage. Our high-intensity completions are driving improved well performance in the Graben area. We brought on one new Eagle Ford well in the Graben this quarter and have additional testing plan for later this year.

In the Duvernay, we ramped up drilling activity over the quarter, and our first completions for the year have recently started. We are well positioned entering breakup with all of our pipelining work already completed. We have also implemented infield sand storage in the Duvernay and have over one week of sand supply already in place. Across the portfolio, our operations are well on track to deliver our guidance targets.

I will now turn the call over to Sherri.

[Sherri Brillon, executive]

Thanks, Mike. Q1 was another strong quarter of financial performance, with net earnings up from last quarter and with operating earnings and cash flow at higher run rates than last year. Our plan for 2018 is on track, with cash flow expected to balance with capital investment over the year. Higher activity levels in the first half will see a higher proportion of CapEx spending, with cash flow growing significantly in the second half of 2018. Cash flow margin came in strong at $13.70 per BOE, and we're confident in our full year target of $14 per BOE.

Our operating margin continues to grow quarter after quarter. This measure has grown consistently through the execution of our plan, and we are well positioned to capture upside to higher prices in 2019 and beyond. Our Q1 price realizations show the benefits of our market diversification, and we are well positioned to manage the volatility in AECO in Midland markets. In addition to strong price realization, our steady improvement in netback highlight the benefit of managing costs to fully capture price upside.

In March, we follow through with our commitment to return capital to our shareholders. We commenced our share buyback with an outlay of $111 million, reducing shares outstanding by $10 million or about 1%. This strengthens our long-term per share growth rates. We expect to continue with our buyback through the year as we recognize an opportunity to grow per share financial results in a meaningful way on a low-risk basis for our shareholders.

We have renewed our revolving credit facilities, now fully committed to July 2022. Our strong balance sheet and capital discipline have allowed us to continue to have only one financial covenant in our facilities. This covenant, based on a debt-to-adjusted capitalization threshold of 60%, ensures Encana can be resilient through the cycle. At quarter-end, we are at only 22% on this measure.

Capturing margin upside is a critical success factor in the E&P space. Capital discipline means not letting inflated project and operating cost erode returns or margins. Our first quarter is a great example of upside capture to our margins. In Q1, top line realized prices were 23% higher than full year 2017, driven by strong WTI prices and our market diversification strategy. Renee will share specific example of revenue diversification in our Canadian gas portfolio that generated a $1 per BOE margin uplift to the entire company on the quarter.

Our disciplined cost control is continuing to work. Compared to last year, our costs are up only slightly, and that increase is due to our market diversification, resulting in additional transportation costs to access other sales points. In return, we achieved better-realized pricing and take lower risk by diversifying our exposure to different markets. Our mix of products has also improved versus last year, with our liquids at about 45% of production this quarter versus about 41% last year.

The combination of cost control, market diversification and improved liquids mix resulted in a Q1 netback increase of 38% over our 2017 annual average.

I'll now turn it over to Renee to discuss our strategy to expand margins.

[Renee Zemljak, executive]

Thanks, Sherri, and good morning. Encana's approach to marketing, and the market fundamentals has been one of our core principles of our strategy since 2013. Market diversification and basin-specific economics impact capital planning and, therefore, receive a great deal of our attention. We believe there is real value and have enough focused multi-basin portfolio. Having 4 core positions gives us tremendous advantage when it comes to managing risks related to market access and infrastructure. It gives us enormous flexibility and the opportunity to redirect capital as required. We connect market intelligence and risk mitigation to corporate strategy, planning and upstream execution. It is the strong integration across the company that enables us to effectively mitigate regional price risk, including AECO gas and Permian oil dynamics. There are 3 main components to our approach to commodity monetization. First, we need to ensure our ability to physically access markets to sell our products. Practically speaking, this means that we have cost-effective transportation and midstream for our existing production and our future growth. Second is our drive to maximize price realizations. We focus on cash flow, specifically cash flow margin. And we actively seek out physical market diversification.

We also employ a structured financial risk management program to reduce cash flow volatility and manage balance sheet risk. This includes managing both benchmark price risk and basis differentials. Finally, we support the company's long-term strategy to the formation of flexible and reliable midstream transactions. An example is the recently announced Keyera transaction, which supports our growth in the Pipestone Montney. This agreement provides us with a fit-for-purpose third-party midstream solution, while allowing us to keep our capital focused on what we do best, drilling high-return condensate rich wells.

The value of our marketing approach is evident in our first quarter results. In Canada, we have captured a realized natural gas price, which is almost equivalent to the NYMEX benchmark, effectively eliminating short-term AECO price risk. We have achieved this through a combination of physical transportation and financial hedging. We have secured firm intra-basin service on NGTL and firm export capacity to the Dawn West Coast in Chicago markets. In addition to full assurance, this pipeline access provides exposure to numerous sales points. While AECO pricing remains under pressure, we are currently capturing price upside in excess of our transportation costs. The base of hedging programs further reduce our exposure to AECO price risk. For 2018, we have financial basis hedges and $475 million a day of our AECO gas at a discount of $0.87 to NYMEX. This level of production -- of protection continues for 3 years, as we have nearly a half of bcf per day, hedged through 2020, at an $0.88 deferential to NYMEX.

In the first quarter, we achieved a realized Canadian gas price of $2.87 or about 96% of the NYMEX benchmark price. Our physical diversification contributed approximately $0.70 per realized price, while our financial basis hedges contributed another $0.39. Over this same time period, the U.S. AECO price was only $1.48. The combination of these activities results in flow assurance in the gas price that is substantially better than AECO forward market. In 2018, we expect to have less than 10% of our Canadian production exposed to AECO gas prices.

So applying the same principles to the Permian basin, we have achieved a very similar outcome. To reduce our Midland differential exposure, we have utilized a combination of reliable oil gathering arrangements; firm physical transportation; financial basis hedges; and firm sales to counterparties with basin egress. Approximately 90% of our oil is gathered on the medallion pipeline system, which has connectivity to most major market outlets. Pipeline connectivity minimizes reliance on trucking, yielding significant cost savings and improving our margins. Our firm pipeline access to the Gulf Coast market grows annually with Encana's production. And we have additional Gulf Coast netback sales, which further reduce our Permian price exposure. To manage the remaining Permian price exposure, we have hedged Midland differential at an $0.81 discount to WTI for 2018 and a discount of $1.42 for 2019. Between our physical transportation and our basis hedges, we have no Midland price exposure in 2018, and we have covered the vast majority of our 2019 exposure.

Our Permian natural gas is gathered by various low-pressure service providers. Our percentage of proceed contracts provides strong alignment with our midstream partners. And if required, we do have take-in-kind rights on a significant portion of our natural gas midstream contracts.

And finally, we have 2018 and 2019 Waha basis hedges in place at a $0.35 discount to NYMEX. Over the course of our 5-year plan, Waha gas represents less than 2% of total company cash flow. We did see strong pricing on our Permian oil volumes in the first quarter, where we realized an average price of $63.27. This is approximately 101% of the WTI benchmark. And even though the Midland oil differentials have substantially weakened for 2018 and '19 period, our marketing arrangements and our basis hedging program will enhance our margins, and they will protect our cash flow.

We are confident that, over the long term, infrastructure additions will generally keep pace with production growth. However, the recent short-term price weakness is an example of the importance of having a regionally-focused price mitigation strategy.

I will now turn the call back to Doug.

[Douglas Suttles, executive]

Thanks, Renee. We are well positioned to execute another year of strong growth for Encana, as we prepare to cross the [ 400,000 ] BOE per day milestone later this year and deliver free cash flow next year. We have an exciting 5-year plan that delivers compound annual growth and cash flow of 25% as well as free cash flow of about $3 billion at what now looks to be relatively conservative prices.

We are firmly on track to deliver our 2018 guidance. Our focus on generating quality corporate returns is driving continued improvement in the underlying performance of our business. We are boosting well productivity and leading the industry in extracting maximum value from our assets. We are fully offsetting inflation and ensuring that the improvement in commodity prices flows through to our margins and returns. We are managing risk and optimizing the prices we realized for our products. We are exercising capital discipline, delivering 30% annual production growth within cash flow. And we will continue to return capital to shareholders through our share buyback program.

Thank you for listening to us so far. And we'd now be happy to take your questions.

[Operator]

[Operator Instructions] Your first question comes from Gabe Daoud from JPMorgan.

[Gabriel Daoud, analyst]

Certainly appreciate all the prepared remarks, but maybe can you just talk a little bit about the CapEx and production trajectory throughout the rest of the year, just to get us a little bit more comfortable with the ramp and the exit into '19? For instance, I guess, the activity levels that you guys exited at in 1Q, that should largely be held constant throughout the year? And so CapEx, perhaps moves -- I guess, moves lower throughout the year? Can you just -- a little more thought on that?

[Douglas Suttles, executive]

Yes, Gabe, thanks for the question. We tried to highlight some of this during the call. But essentially, in the second half of last year and, particularly, in the Duvernay and Eagle Ford, we ramped down activity, and we restarted and ramped up that activity here in the first quarter. And what you'll see is then, we see decline coming off the peak in 4Q. And we'll actually see production build in the second half of the year in those 2 assets. If I, kind of, go asset-by-asset, we've ramped up to 3 rigs in the Eagle Ford today. That will actually ramp down a little bit as we go through the year. We currently got 4 rigs running in the Duvernay at the moment, but that will also ramp down as we go through the year. The Permian will be relatively flat, averaging between 4 and 5 rigs similar to last year. And as Mike said, we started the year in the Montney at 13 rigs, we're currently at 10. And a lot of that is, as we build capacity to fill these new liquids' hubs. So -- and I think Sherri highlighted this, we have a bit more front-end first half capital than second half, and we have -- a lot of our production growth shows up in the second half of this year and particularly, from the Eagle Ford, the Duvernay and the Montney.

[John Gerdes, analyst]

And then in the Permian in 1Q, was there any infrastructure spend in that capital number of about $240 million for the quarter?

[Douglas Suttles, executive]

You know, Gabe, very little. In fact, one of the things that we're really proud of is, Mike mentioned our $2.50 per BOE operating cost on our horizontal wells, I think that's right there with the very best in the basin, and we did it without spending hundreds of millions of dollars each year on infrastructure. Essentially, I think we've been building our latest 2 water resource hubs. But I think as we've talked before, those cost in the neighborhood of $3 million. So it's quite small. The infrastructure spending's very small.

[John Gerdes, analyst]

Great. And then just last one for me. Just sneaking in a Montney question, at Tower, on the completion side, can you just talk a little bit about how that's different or how that's changed relative to the 3Q, 4Q Tower cubes that you guys put on? And then also, at the Tower cubes, was there any wellbores in the lower Montney at all?

[Douglas Suttles, executive]

Yes, I'll let Mike pick this one up. I mean, fundamentally, what we've been doing right across the portfolio is advancing these high-intensity completions, which generally is driven by tight cluster spacing. But Mike, why don't you pick that up if you would?

[Michael McAllister, executive]

Yes, you bet you. Yes, we've increased our intensity of completions in Tower. We got to up to -- move from up to almost 2,000 pounds per foot on certain wells and down to 10-foot cluster spacing as well in the richer part of the zone. And yes, we have tested the Sexsmith, the lower portion of the Montney in Tower as well.

[Operator]

Next question comes from Benny Wong with Morgan Stanley.

[Benny Wong, analyst]

Just wanted to touch on the buyback. It seemed like it came in at much higher pace than we were expecting. Just wondering if you can speak to the strategy around that. Was it just the stock looked particular compelling at a certain level? Or was cash flow just much stronger with oil prices? And how you're thinking about potential pace of the remaining authorization?

[Douglas Suttles, executive]

Yes, Benny. If you think about this, when you actually look at the number of days, you can actually be in the market buying the stock. It's much more limited than you realize because of blackout periods and other things. So you can't ratably do this, sort of, month to month. We fully expect, based on what we see as current conditions, to execute the full program. And that's like, for instance, we've been out of the market now, essentially the entire month of April because of the blackout period. So it's not really a surprise to us. We're not trying to be overly complex here in how we manage this program, trying to get smarter than the market. That's what you guys do, not us. But I would expect us to do it. It really wouldn't have surprised us. And I'd expect by the end of the year, if conditions stay the same, that will have fully executed the program.

[Benny Wong, analyst]

Great. I appreciate the color on that. And just want to jump over on Permian differentials and will love to get your thoughts on this as well, Renee. We've seen differentials really widen out what seems to be a lacking of pipeline until the back half of 2019. I know you guys are well mitigated from this, but want to get your outlook here and how wide do you think these differentials can go? And how's the industry, kind of, get the production to market until those pipes come in?

[Douglas Suttles, executive]

You know, Benny, Renee can fill in lots of information here. But what's interesting is if you look at this both in Midland basis and in Waha, we believe we could see this coming for quite some time. And very similar to what we did at AECO, which is trying to understand what's going to happen with regional growth and how that fits with export capacity, then how do you position yourself, both physical and financially. Because in some ways, we're right back to where we were in 2014. But Renee, maybe you'll fill in some thoughts. I'm sure Benny would like to know exactly what dips are going to get to.

[Renee Zemljak, executive]

Well, thanks, Benny. I don't know that I can predict exactly where the differentials are going to go to. We are concerned that they will continue to widen. The basin most likely is going to need a combination of trucking and rail to actually get the barrels to market. As I'm sure that you are aware, there are several pipelines that are expected to come into service in 2019. In fact, the most recent one that was announced that went to FID was the Gray Oak Phillips 66 pipeline. So we are expecting differentials to continue to widen from here, and it will go to trucking and rail economics. It could go out as wide as maybe it's $14, $15. We're not sure. But we expect to continue to see pressure on those differentials until the end of 2019. Longer term, though -- I would like to reiterate, though, that we believe the infrastructure for the most part will keep pace with production growth. So we'll see, we'll see what 2020 brings us.

[Operator]

Next question comes from Brian Singer with Goldman Sachs.

[Brian Singer, analyst]

I wanted to follow-up a bit on the Montney with regards to the production trajectory. You further accelerated the number of wells drilled to 40 in the quarter. Can you just talk a little bit more on the timing of that ramp up? And to what the magnitude of higher condensate yields and the impact that has on the ability to process that condensate and get those wells to sales?

[Douglas Suttles, executive]

Yes, yes, Brian. I mean, Mike will fill in a lot of the information here. But we do expect to see pretty significant liquids' growth quarter-over-quarter from Q2 to Q1. We do have -- Mike mentioned this, we do have a plant turnaround in one of our gas plants in the quarter, which is going to impact volumes a bit. That's been planned. That's part of the plan. And then, of course, in the second half of the year, we have the 2 liquids hubs coming on: one in Cutbank Ridge in British Columbia, and the other one at Pipestone in Alberta. And of course, what we're doing is drilling -- starting to drill wells to be able to access that. But maybe, Mike, you can add some more color.

[Michael McAllister, executive]

Yes. Here -- come this May 22, we're scheduled to come down our Sexsmith plant for turnaround, which is going to last about 18 days. So that impacts Q2. And as I mentioned, about 5,000 BOE per day, with respect to the liquids' growth, I mean, we're really confident. We're seeing some great well results that support our ability to grow our production, Brian, up to -- between 55,000 to 65,000 barrels a day here coming into Q4. That's supported with 2 liquids' hubs, which really the front-end liquid separation of our gas plants. One in the north central liquids' hub that will feed our Tower plant, take the liquids out going into our Tower gas plant -- excuse me, Sunrise gas plant and then in Pipestone. So generally speaking, we'll see good liquids growth starting in Q2, but it will ramp up as we approach Q4.

[Brian Singer, analyst]

Okay, thanks. And my follow-up is with regards to the Permian. I think you mentioned that you'd be moving towards 100% sourcing from local sand. Can you just talk about the logistical risks, if any, that you see in moving that sand to where you need it to be?

[Douglas Suttles, executive]

Yes, Brian. Just one thing I want to mention because some of the mindset that, I think, that Renée really focused on is -- in her talk, we try to do right across the business, which is actually looking for both risk and opportunity. And we've talked about this in the past, particularly as we exited '16 into '17, where we saw industry picking up and said, "What are the risks that it presents? How do we get in front of it? And what opportunities do we have to create savings to offset some of that pressure?" And of course, one of the things we've done is we've fairly quickly moved to local sand and have been supportive of that. Managed that logistics ourself. I'll just give you another interesting way we think about this. We've been leading a group of operators in the basin to figure out how we can get trucking more productive. And this is an example of, kind of, how we think where what we've said is the constraint really isn't on trucks, it's on truck drivers. So how do we get every truck to haul more sand, and we've been working with the legislature and the regulators to do things, like can we haul? Can we pull double trailers? Can we add an axle to the trailers and increase the load capacity of the trucks? And I just emphasize this because this isn't the largest companies in the world who think about this. This is us. We get in front of these issues. We think about them and then, in many cases, it requires collaboration with the other operators to do that. But more specifically, Mike can tell you about, we did feel some pressure in the first quarter as some of the local mines are a bit late coming on.

[Michael McAllister, executive]

Yes, thanks, Doug. Yes, Brian, the -- we -- basically, local sand that we sourced here in Q1 was about 40% of our requirements. The remainder came from on rail and using our terminals. The expectation is we'll get to a 100% local sand here by the end of the year. Savings on local sand versus railing it in is about $0.02 per pound, going from $0.06 down to $0.04 per pound. The issues were with the 2 sand mines, it's in there -- it was in their assembly line related to some dryers, which have been repaired, and so they're ramping up now to increase our local sand supply going forward. With respect to transportation, as Doug mentioned, the constraint is on truck drivers, not necessarily on trucks. And we went to the sandbox system, and it's allowing us to move our sand basically on flatbeds, which is a lot more accessible. So that's also given us an advantage, with respect to logistics in moving the sand to our well sites.

[Douglas Suttles, executive]

Yes, Brian, I think the last thing I'd just add to Mike's comments is one of the advantages we find of self-sourcing here is we're directly connected to a logistics chain, so we can coordinate that with our activities where, when others are relying on maybe the service provider manage that, in many cases, they have no line of sight to constraints in the system and how that might impact their plans and their schedules. But because we manage that logistics chain ourselves, we can then link any disruptions there with our activity and not be surprised. So that's an another advantage of the self-sourcing model.

[Operator]

Next question comes from Nick Lupick with AltaCorp Capital.

[Nicholas Lupick, analyst]

Just a follow-up on Brian's question in the Montney. I just wanted to take a quick -- have a quick conversation about the condensate production that you're getting from the Tower cubes. Obviously, there's a fairly sizable variance from cube-to-cube. As you said during the call, not all of them are in the same resource window. So I just wanted to talk to you guys about, kind of, the back half of the year, how many cubes do you expect to bring on? Which resource windows do you think those will come on in? And I guess what I'm trying to get at is how much of that Q4 production growth is coming from Pipestone versus the cube developments in Tower?

[Douglas Suttles, executive]

Yes, Nick. I don't think we can probably -- we don't have the information right at hand for the call here to kind of go through a lot of detail on this, but Corey and the team can follow up afterwards. If you look at the shape of it, the Pipestone piece is a modest proportion of it. I -- It's not -- The bigger chunk is actually in Cutbank, just because of the size. The slight difference there, as you know, in Pipestone, we effectively own 100%, whereas in Cutbank Ridge, we're -- we have a partner there, Mitsubishi, and we own 60%, and they own 40%. But the majority of the volume is coming out of, what we call, the North Central Liquids Hub and Cutbank Ridge and then the remainder is Pipestone. But it probably easiest if we just follow up after the call with you.

[Operator]

Next question comes from Bob Brackett with Bernstein.

[Bob Brackett, analyst]

Can I follow up on the Permian market diversification? Can you talk about just your philosophy for 2020 and beyond?

[Douglas Suttles, executive]

Yes, Bob, a great question. I -- And Renee kind of highlighted this. She kind of started that with AECO. And we actually think that using a combination of fiscal transport combined with what we call firm basin -- our firm in-basin sales to people with transport and then using the derivatives market for the remainder of the risk is a right balance. And the reason for that is if market conditions change, let's say, oil prices fell dramatically, you don't want to be long physical transport because if you're long, probably everyone else is long, and it just becomes a drain on your business. Yet at the same time, you can -- we actually believe you can normally see -- it's a lot easier to see these risks, and we think manage these risks, it is the commodities themselves. We think you can actually -- if you study it hard enough and we have -- one of our 4 pillars is the midstream marketing fundamentals' pillar, where we spend a lot of time watching what's happening in the basins we operate in, not only from operators and what they're doing with capital and performance, but what's happening with the infrastructure. Then mix this combination of physical transport, market diversification and financial derivatives to take out short-term risk, and the short term can be a year or 2. If it's decade-long, that's where the multi-basin portfolio comes in, where we'd actually just rotate capital out of the play into a better-positioned, more advantaged play.

[Bob Brackett, analyst]

Got you. And a follow-up on the Permian LOE being down about 250 BOE. Can you talk about what artificial lift technology are you using? Or give some sort of insight into how you're keeping that number so low?

[Michael McAllister, executive]

Yes, Bob. Basically, when we -- 86% of our production, to be more exact, probably more exact than it should be, is actually related to horizontal wells. So that 250 per BOE is our horizontal well LOE. And generally, the -- we progress through our artificial lift. Typically, we want to get the water off those wells as quickly as we can, so we go -- start off with the ESPs, transitioning to gas lift, and then, finally, to rod pump over course of the time of that well's life. So ESP, gas lift and then, finally, rod pump is the progression.

[Douglas Suttles, executive]

And Bob, one thing that helps here, too, Mike mentioned in his part of the call there is, we've been very aggressive on using recycled-produced water in our completions and our development program. And that saves us about $0.80 a barrel on disposal costs. So not only do we have secure supply, not only we're making sure we're not competing with other users, it's also a lot cheaper than source water for frac jobs, but it also cuts our operating cost. And we see that percentage of produced water continuing to grow over time. We've had some pads as high as 80%. We pumped entire stages at 100% produced water now. And Mike already mentioned that we see a substantial growth year-over-year in the percentage of produced water. And it does contribute to our savings.

[Bob Brackett, analyst]

And that $0.80 per barrel, that's net of the clean-up cost of the produced water, the treatment cost?

[Douglas Suttles, executive]

Yes, one of the things, Bob, we found -- we started working on this a few years ago, is that we don't have to clean it up very much. The only thing we really have to get out of the produced water is the oil. So obviously, it comes from our tank batteries and goes to our disposal facility. Then it runs to these water resource hubs, which fundamentally just use 3 tanks in a [ rear ] type system to make sure we don't have any oil. But the operating cost of that is very cheap. This is the cool thing about our water resource hubs. They store a 1.5 million barrels of water. It's in line to earth and pit, with a section for produced water and a section for source water. And we -- it also means we can do large multi-well pads because we prestored the water before we start the completions. And I think we've talked about this, we can build one of these in 90 days, and they only cost $3 million. That's why, I think, on the earlier question about infrastructure spend, our infrastructure spend is very low, and our operating costs are very low.

[Operator]

[Operator Instructions] You have a question from Jeffrey Campbell with Tuohy Brothers.

[Jeffrey Campbell, analyst]

I was wondering if you could talk about the extent to which waterborne exports are parts of your overall Permian and Eagle Ford sales plans?

[Douglas Suttles, executive]

Yes, Renee can pick this up. But we essentially can sell crude both in Houston and, effectively, the recent deal we've struck out of Corpus and access Brent pricing if we choose to.

[Renee Zemljak, executive]

Yes, so our sales portfolio does include a combination of locations. So like Doug said, we can go to Houston, we can go to Corpus. We do have access to Brent if the spreads actually make sense. And with the volumes that we have most recently delivered into Houston off of the AECO pipeline, we have entered into self-transactions that were Brent-related. They were Brent netback. So as we go into the future, we do foresee that we'll have a combination of Brent netback, Corpus netbacks and Houston netbacks to get back to our Permian pricings.

[Jeffrey Campbell, analyst]

Okay, thanks for the color. I noted the pretty active Austin Chalk program with interest. I just wanted to ask couple of questions. One, are these all going to tend to be high oil cut wells, like the one that you reported in the press release? And second, do you see these primarily as stand-alone wells? Or can they be incorporated into Eagle Ford beds?

[Michael McAllister, executive]

Yes, the oil cut will be consistent. We're drilling. Basically, some wells are offset to existing wells. And really pleased, as I mentioned, with the results that we're seeing. And yes, we incorporate these into, basically, the Eagle Ford cube with Eagle Ford wells and Austin Chalk both producing into the same infrastructure.

[Douglas Suttles, executive]

Yes, Jeff, the concept we've had here, we stepped into this at a modest pace. I think we're up to about 20 Austin Chalk wells that we've drilled. And one of the things we did is -- it's a more complex play than the Eagle Ford. Many people know it's got a long and colorful history. And because it overlies our Eagle Ford, the land is already held by Eagle Ford production and where we're drilling the wells is accessing facilities that were built for the Eagle Ford development. And that's also impacted where and the pace of how we develop because we have wanted not to have to build new additional surface facilities. And that -- those 2 things together have largely driven the pace. And I think Mike highlighted earlier in the call that we -- the good news is we've had really consistent results. We haven't had a bad well. And -- But it is technically complex. It isn't as airily continuous and contiguous as the Eagle Ford. So I think it's important for those who have the acreage, but it's clearly not going to have the same scale as the Eagle Ford had.

[Jeffrey Campbell, analyst]

I'd say, based on history, having no bad Austin Chalk wells is pretty much a record. So that's pretty great. If I could sneak one last quick one in. Slide 47 said that Encana will design, construct and initially operate the Keyera Pipestone facilities. Can you add some color on how or why you would cease to be the operator of those facilities?

[Douglas Suttles, executive]

Well, we did this in the -- what was originally the [ variance ] in KKR deal and now Pembina. It's one of the things that the third party midstreamer typically wants is the option to become the operator. And that may, obviously, tie in with their future plans in the area. What it allows us to do, it creates a unique piece of linkage because if we can drive efficiency into the construction and the capital of these plans, we both benefit from that, particularly with the contract structure we have. And then by us operating it early on, we establish the baseline for the cost of these plans, which also creates a strong linkage in the future. And time will tell whether they decide to exercise that option or not. But it's something that was important to them, and as long as we can set that baseline, we were happy to accommodate that.

[Operator]

At this time, we have completed the question-and-answer session and will turn the call back over to Mr. Code.

[Corey Code, executive]

Thank you for joining us on our call this morning. This now concludes our call.

[Operator]

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