Brendan McCracken - Encana Corp. Douglas James Suttles - Encana Corp.

Sherri A. Brillon - Encana Corp.

Michael G. McAllister - Encana Corp.

Reneé E. Zemljak - Encana Corp.

Greg Pardy - RBC Dominion Securities, Inc. Gabriel J.

Daoud - JPMorgan Securities LLC Menno Hulshof - TD Securities, Inc. Amir Arif - Cormark Securities, Inc.

Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.

Stephen Richardson - Evercore Group LLC Brian Singer - Goldman Sachs & Co.

Thank you, operator. Welcome, everyone, to our first quarter results conference call.

This call is being webcast and the slides are available on our website at encana.com. Before we get started, please take note of the advisory regarding forward-looking statements in the news release and at the end of our webcast slides.

Further advisory information is contained in our Annual Report and other disclosure documents filed on SEDAR and EDGAR. I also wish to highlight that Encana prepares its financial statements in accordance with U.S.

GAAP, 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. Reneé Zemljak, our Executive Vice President of Midstream Marketing and Fundamentals, will provide an update on our risk management and market access strategies.

We will then open the call up for Q&As. I'll now turn the call over to Doug Suttles.

Thanks, Brendan, and good morning, everyone. Thank you for joining us.

Q1 marks another very solid quarter of execution. We continue to be highly focused on delivering quality corporate returns.

We started this year with four key objectives. The first was for it to be the safest year in Encana's history once again.

The second was to go from production decline to production growth by the middle of the year, what we call the bounce. The third was to deliver at least 20% production growth in our core assets from the fourth quarter of 2016 to the fourth quarter of 2017.

And the final objective was to do all of those first three items while holding on to the efficiencies we worked so hard to create in 2015 and 2016. So how do we do to the first quarter of this year?

First, I'm confident we'll achieve our objective to once again have our safest year ever. On the production bounce, we're off to a great start.

Production in the first quarter has been very strong, largely underpinned by our emphasis on well performance. Completion design improvements are driving strong production performance across the portfolio.

I'm confident not only in delivering on our mid-year bounce, but also on delivering at least a 20% production increase in our core assets from the fourth quarter of last year to the fourth quarter of this year. And finally, on efficiency, the teamwork between our supply chain organization and our operating team has been incredible.

The combination of very smart commercial work combined with continued efficiency improvements across the portfolio means that we're not only meeting our objective of holding off inflation on well cost but in many cases actually continuing to reduce cost in the business. So how are we doing all of this?

A big piece of it is our culture of innovation. We're leading the industry in what we call the development of the cube.

That is stacked pay reservoirs where we're using large multi-well pads drilled with multiple rigs simultaneously and completed with multiple frac spreads at the same time. That's delivering not only lower development cost but it's improving recovery from the reservoir.

The combination of innovative operations, commercial ingenuity, and our belief that optionality is valuable is creating value and managing risk. As an example, in the Montney we continue to increase liquids production and improve well productivity.

Commercially, we recently announced a combination of firm transportation arrangements to multiple markets in a basis hedging program which will effectively manage price risk for our Western Canadian gas production. So as we exit the quarter, I'm very confident that we're going to deliver on our four key objectives for the year.

I'll now turn the call over to Sherri.

Thanks, Doug. A year ago, the focus for the industry was adapting to the low commodity price cycle.

Today, three of our four core assets are free cash flow-positive and the Permian is approaching that threshold. This clearly indicates our business works at today's prices.

Encana's first quarter financial result shows strong performance in net earnings and non-GAAP cash flow. Encana's continuous focus on reducing cost and growing high-margin production is driving these results.

Versus the first quarter of 2016, Encana has lowered transportation and operating costs by $100 million or $0.90 per BOE. These cost reductions combined with growth in our higher value oil and condensate production and stronger pricing have delivered a fivefold increase in operating margin excluding hedges.

Net debt is $1.5 billion lower versus Q1 of 2016 which has reduced ongoing interest costs. Through 2017, Encana expects to utilize cash from operating activities and cash on hand is on the capital program.

Combined with the cash equivalents at March 31, Encana has over $5 billion of liquidity available. First quarter production came in ahead of our expectations with the core assets coming in flat versus Q4 at 237,000 BOE a day.

We expect total production will begin to grow mid-year. Our high-margin liquids production growth has already begun.

Oil and condensate production increased by 2,000 barrels a day this quarter. We expect this high-value production to grow every quarter this year driven by steady growth in the Permian and a significant increase in the Montney in Q4.

Our first quarter results demonstrate we're on track to achieve our 2017 guidance which remains unchanged. On all products, our first quarter production results are above our forecast issued on our February call.

These results set us up to deliver over 35% growth in oil and condensate volumes in the fourth quarter of 2017 versus the fourth quarter of 2016. In our core assets, we expect Q4 2017 total production growth will exceed 20% versus the fourth quarter of 2016.

Natural gas production is expected to decline until the fourth quarter when we will see significant growth in the Montney. The Montney plants continue to track ahead of schedule to be operational in the fourth quarter.

I'll now turn the call over to Mike.

Thanks, Sherri. As Doug and Sherri both mentioned, we're off to a very strong start in 2017.

We're running ahead of our production plan and the execution of our capital program is going very well. We're also focused on maximizing our corporate returns and we continue to demonstrate leading results across our portfolio.

This is a direct result of our strategy. We drill only premium return wells.

This is possible because of our deep inventory in the highest return plays in North America. On top of that, our culture of innovation means we leverage technology and planning to ensure we're always improving our capital productivity.

Having the best rocks and being a leading operator is a powerful combination. The two plots you see on the slide are sourced from independent research on breakeven cost for 2016.

As you can see, we're performing amongst the very best in both Midland Basin and in the Montney. We're also very encouraged because we have continued to get better in 2017.

We also have a very commercial mindset. We want to make money, not just production.

As part of this, we think about managing risk while preserving optionality. We've work hard to create flexibility to take advantage of our short cycle multi-basin business.

With our premium well returns, disciplined capital allocation, and low overheads, we believe we will generate quality corporate returns through the cycle. Our approach to development utilizes large multi-well pads, advanced completion designs, integrated infrastructure, and detailed planning to maximize returns.

In the Permian and the Montney, we have thousands of feet of stacked pay. 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. Our approach is aimed at getting at the most value at the highest returns from our stacked pay resource.

This approach has benefits both above ground and below ground. In stacked reservoirs, there's a clear benefit to drilling and completing the entire cube at once.

Historically, our industry has been slow to identify the optimal well spacing for unconventional plays. This is the large infill drilling programs years later to try and boost recovery factors.

In some cases, the result is a parent-child relationship between the old and new producing wells where the new child wells are simply not as productive. In our approach, all wells are parent wells.

We minimize the risk of communication with depleted reservoir that makes the subsequent wells less effective. We enhance productivity by creating a more complex fracture network.

We also improved our uptime by avoiding clean outs due to offset frac hits. We believe this is the best approach to maximize corporate returns.

In the Permian and the Montney, we've been studying this for several years. We did the first real-time pressure monitoring of frac jobs and production from our Midland County Box Well (11:10) back in 2015.

Those results were applied to our first 14-well cube development on the RAB Davidson pad in early 2016. We then put those learnings to work on the 12-well Abbie Laine pad and most recently on another 19 wells back on the Davidson pad.

Above ground, our approach to developing the cube gives us significant advantages. We can maximize efficiencies and get higher utilization from our equipment, crews, and infrastructure.

During drilling operations, we use multiple drilling rigs to reduce cycle time and shared services. As our team identifies efficiencies, they quickly apply them to the next well which are drilled just feet away.

This approach is delivering some of the lowest drilling cost in the industry. During completions, the scale effect is even more impactful.

The improved horsepower utilization and reduced cycle times lowers our capital costs. Stockpiling resources on location for multiple frac crews drops costs and increases reliability using integrated water infrastructure to supply and recover frac fluid and eliminates trucking and lowers both capital and operating costs.

In addition, the opportunity for real-time knowledge transfer from rig-to-rig or spread-to-spread on a single location accelerates learning. With crews working on one site, ideas can spread much more quickly.

No rig or spread wants to be the slowest on our pads. Our integrated infrastructure lets us save money by recycling water and reducing well site facilities and pipeline costs.

Combined, these two items save $0.5 million a well. Our approach has established us as a leader in stacked pay unconventional rocks.

I fully expect us to continue to find new ways to tune our approach by embracing technology to create value. Let's look at some recent results from our development approach.

This quarter, we brought on the 12-well Abbie Laine pad in Midland County. These wells are drilled into five benches in the Wolfcamp and Spraberry.

As you can see, the production performance is well ahead of type curve. Daily production peaked at 14,000 BOE per day and the average IP30 was over 1,000 BOE per day.

Performance continues to be strong after 65 days of production. This is our second full scale development pad in the Permian.

The first was the original 14 wells on the RAB Davidson pad that we brought on last May. Our third full scale pad saw us return to the original Davidson pad and drill a further 19 wells in the opposite direction to the original development.

For only a few days into ramping-up production from this pad, total production is at 18,000 BOE per day, which includes 14,000 barrels per day of oil. These strong rates are really encouraging this early in the clean-up process.

Altogether, we now have 14 dense cube development wells on production in the Permian. Based on these results, we expect to be able to update type curves and inventory later this summer.

Structured innovation lets us try many new technologies at the same time across our multi-basin portfolio. This accelerates our learning curves across all assets as we rapidly transfer knowledge.

In the Montney, we've begun applying the advanced completion designs that we first trialed in the Eagle Ford late last year. The initial results are impressive.

We've also recently completed the installation of a downhole fiber optic system. This is providing us with real-time data to determine cluster effectiveness.

We can see how much fluid and proppant each cluster took during the completion and how much each cluster is contributing during production. Our engineers designed and implemented this in a 10,000-foot lateral and we pumped eight different versions of our completion design across 30 stages.

We're capturing unique data from all 150 clusters that will help us evaluate the effectiveness of each design. In our Permian completions, we're trying new high-viscosity friction reducers and self-suspending proppants with the aim of reducing well costs and improving productivity.

In the Eagle Ford, we're moving to the next phase of advanced completion design. We've now reduced cluster spacing to 10 feet.

We're also adding fracs to the heel of our Lower Eagle Ford laterals into the Upper Eagle Ford and Austin Chalk zones. This optimization adds productivity to our wells and gives us results in the upper zones in the stack.

In the Duvernay, we started using hybrid metal-to-metal drilling motors. These have reduced risk of failure and can lead to faster drilling times.

We're also trying dissolvable bridge plugs during completion operations with the goal of eliminating coil tubing mill-outs. By sharing the learnings across the company, we can instantly apply successful ideas and ensure no time is wasted on those ideas that don't work.

We're seeing there's still considerable opportunity to boost well productivity through completion design. This quarter, we continue to have success with our advanced completion designs in the Eagle Ford and the Montney, and we pumped our first versions in the Duvernay and Permian.

The principle behind these designs is to use tighter cluster spacing and thinner fluids to enhance fracture geometry and complexity. During the quarter, we brought on three new Austin Chalk wells with an average IP30 of 1,285 BOE per day including 1,000 barrels per day of oil.

We also brought on five additional Austin Chalk wells in mid-April. The early results are really encouraging with the wells currently averaging 2,150 BOE per day.

Our advanced completion results in the Eagle Ford are compelling. We have now made this our standard design in both the Eagle Ford and Austin Chalk zones.

We transferred this technology into the Montney. The initial results in both Tower and Pipestone are generating strong incremental returns.

We now plan to use the advanced completions on all our upcoming Pipestone wells. We're also watching the Tower results closely and we'll make a decision ahead of the upcoming program.

With these results, we expect to be able to update type curves and inventory this summer. As we expected, the sharp increases in activity by the industry has created upward pressure on service costs.

This is especially true for pumping services in the busier basins like the Permian and Montney. With our proactive approach, we've fully offset inflation with efficiency improvements and effective supply chain management.

We're on track to deliver flat well costs versus 2016. In fact, in the first quarter we pumped 17% more proppant per foot than our 2016 average while holding well cost essentially flat.

This is a direct result of the seamless linkage between our supply chain and operations team. We control 75% of our capital spending through a centralized supply chain team.

We manage supply chain by self-sourcing the key consumables in our D&C operations like sand, water, chemicals, casing, and drilling mud. This gives us better pricing and improves the security of supply.

We've locked in pricing at attractive rates for frac spreads in both the Montney and Permian. We also have pricing agreements for API Sand that we negotiated in 2015 that extends out to 2020.

We continue to increase our utilization of non-API or brown sand which has the opportunity to further reduce our sand costs. Going forward, we're in a strong position to manage inflation with 60% to 70% of our D&C cost either locked in or self-sourced.

We're also driving operational efficiencies, relentlessly working to reduce the time it takes to drill and complete our wells. I will now turn the call over to Reneé.

Thanks, Mike, and good morning, everyone. Our approach to price risk management reduces cash flow volatility and helps to manage our balance sheet risk.

We utilize a combination of financial derivatives, transportation contracts, and a diversified physical sales portfolio to manage our benchmark price and basis differential risks. For the remainder of 2017, we have a strong hedge position in place with 70% to 75% of our production hedged at attractive prices.

We've also begun layering in protection for 2018. We expect to continue adding incremental hedges over the course of this year.

As of April 26, we have hedged 31,000 barrels per day of our 2018 oil and condensate production at an average price of $55.45. In addition, we've hedged 500 million cubic feet per day of our 2018 natural gas production at an average price of $3.06.

We have also hedged a portion of our Canadian to U.S. dollar exchange rate exposure.

Today, we have executed a total of $500 million of currency swaps for 2017 at an average exchange rate of $0.75. Across our portfolio, our midstream marketing programs are dynamic and they're directly aligned with our strategies.

Our focus is on maximizing our corporate margin, managing price risks, and mitigating market access risk. We have actively managed regional price risk across our portfolio with a combination of pipeline transportation contracts and financial basis swaps.

These arrangements provide a great degree of capital allocation flexibility. They're structured to minimize our overall commitments and they provide secure physical access to downstream markets.

In the Montney, we have a firm midstream and downstream transportation arrangements that are aligned directly with our growth plan. A broad sales portfolio provides diversified markets including sales into either the AECO market which has strong physical reliability and liquidity or firm transportation to neighboring markets which reduce our AECO exposure.

In addition, we use the financial derivatives market to hedge our AECO basis moving our exposure to the Henry Hub. This reduces our exposure to the AECO price risk.

In 2017, slightly less than half of our Western Canadian natural gas production is exposed to AECO pricing. In 2018 through 2020, this drops to less than one third.

The balance of our production is either basis hedged relative to NYMEX or it is expected to be physically exported to other markets. So in the Permian, we have a portfolio of physical sales and firm midstream and downstream transportation agreements that are not subject to take or pay commitments.

More than 80% of our expected 2017 to 2020 oil production is protected from Midland pricing. In 2017, we have hedged 35,000 barrels per day of Midland differential at a WTI less $0.61.

From 2018 to 2020, we've hedged an average of 17,000 barrels per day of Midland differential at WTI less $0.83. Our physical transportation in the Permian includes 25,000 barrels per day on the up and coming Enterprise ECHO pipeline with an option to secure up to an additional 25,000 barrels per day.

Production delivered on ECHO will have direct access to the Houston refinery complex and potential export markets. Today, approximately 80% of our oil is gathered on the Medallion pipeline.

This is a system with great connectivity to several major market outlets. We expect the percentage of our production gathered on Medallion to grow over time yielding a much higher margin and mitigating weather-related production curtailments.

We also have dedicated storage capacity for our Permian production and it is designed to even further mitigate any flow risk. Our Permian natural gas production is gathered by several well-established midstream service providers.

They provide a reliable competitive marketplace with very limited timing risk. We strongly believe that there is sufficient takeaway capacity to support the expected growth through the end of this decade.

And now, I'll turn the call back to Doug.

Thanks, Reneé. As you can see, we're firmly on track to deliver our five-year plan.

Our focus on generating quality corporate returns is driving our decisions and our plans. We're boosting well productivity and leading the industry in extracting maximum value from our assets.

We're fully offsetting inflation and ensuring that improvement in commodity prices flows through to margins and returns. We're managing risk and preserving optionality across our multi-basin portfolio.

We're making innovative commercial deals to optimize the price we receive for our production. As we look out to 2018, we're well-positioned to dramatically grow cash flow at flat commodity prices.

We expect our average margin to expand by another 30% and we expect 4Q 2017 to 4Q 2018 production from our core assets to grow another 30%. And we plan to do all of this while spending within cash flow.

Thank you for listening to us this morning. Happy to take your questions.

Yeah. Thanks.

Good morning. Doug, what do the Austin Chalk results mean for the Eagle Ford in your view?

Yeah, Greg. Maybe I'll flip this to Mike in just a second.

But as we've talked about for a while, I mean, we watched what was happening in the Austin Chalk because we're well aware of the Chalk's history over the last 30 years to try to make sure we understood the geology before we moved ahead, and we think we do. In fact, we're on our third iteration of our mapping of the play, and our well results continue to be very strong.

Now, is this as strategic to us as the Permian or the Montney? No.

It won't have that sort of inventory, but it could materially add to our premium return inventory. I think in February we added 50 wells to that.

We now have 10 wells on production. I'm sorry, it's up to 12 now.

And as Mike mentioned, our worst well is at type curve and our typical well is considerably above type curve. We've been very pleased with the performance, and the good news is it's conforming to our mapping.

So we're finding results consistent. But Mike, what would you like to add?

Not a lot to add to that, Doug, other than just seeing our last five Austin Chalk wells that came on here in just mid-April. So there's still, really, cleaning up.

Our averaging per well, 2,150 BOE per day, which is an incredible rate. So we're really encouraged with our Austin Chalk results.

Okay. Mike.

Just – Sorry. Go ahead, Doug.

Yeah. Just going to add one thing.

Greg, what's been interesting for us is results in a couple of places in our portfolio from where we've been doing our completion design have actually got us facility constrained. The Chalk is one of those where our well performance is bigger than our facility capacity.

And that's the same thing, by the way. We're seeing the same problem in Pipestone.

It's a good problem to have and it may end up meaning that we have to drill less wells this year to deliver on the production we expect and forecast to deliver.

Okay. Any wells that have been on for 180 days now that you can comment on in terms of how well the performance is standing up?

You bet. Yeah.

Our first two Austin Chalk wells were of course (28:35) 7H and 8H. These were actually shorter laterals.

Combined, the two of them together were 6,500 foot, so shorter laterals. The 8H wells after 180 days is doing 2,000 BOE per day; and the 7H, 1,100 BOE per day.

So, both holding in really well and above type curve. So, again, really encouraged.

Excellent. Okay.

Thanks for that.

Yeah. That was the IP180, not the current rate on those.

In fact, if you scale those things out, I think, to our type well it gets out to, like, 2,500 BOE per day, IP180 in around 1,800 BOE. These are incredible wells.

They paid out in sort of three months.

Okay. Thanks for that.

And then maybe just strategically. Doug, your budgets at $55 and $3, notwithstanding all the good work Reneé is doing on the hedging side, if we remain sort of in a little sub-$50 world, I'm not saying that's your base case, but if we do then how do you respond to that and what does that mean for your growth trajectory?

Yeah. Greg, we've done some work on this.

So first of all, as Reneé described, this year we're not very sensitive to commodity price and that was intentional as we go from decline to growth and how we wanted to protect both the balance sheet and the cash flow. So if I look out to 2018 and beyond, because that five-year planning assumption was $55 and $3, we've tested that at well below $50 and we can continue to grow within cash flow at numbers below $50 a barrel.

And that ties back to what Mike talked about where we keep driving efficiency into our program and we now have a quality portfolio which works if today's prices are lower. So, I think as we sit here today, the most likely direction we would take is just slow growth slightly but not much today.

Instead of using $55, if we use $50 we can come very close to delivering the exact same targets we laid out in October at $55 and $3, within our cash flow.

Thanks very much.

Hey. Good morning, everyone.

Maybe just going back to the Permian, on the Abbie and Davidson pad. Is there anything that you could speak to there from a spacing perspective?

Was there anything in particular that you tested that you can talk about?

Well what we're going to do is this summer we're planning to release some of the results. We've now done three of these.

And what we can tell you is that they are at less than 660-foot spacing. We're not big IP24 guys.

We're people who actually like to see that we're demonstrating real value. And that means you have to have enough time on the clock but we now think we will have that on three different locations in the Permian.

But I'm pretty confident you're going to see that we'll be at spacing less than 660s.

Thanks, Doug. And then a follow-up I guess.

The new completion design that you used on the Austin Chalk, so I guess those will be applied to the Permian moving forward. Does guidance already assume this new completion design?

If you could just summarize also the difference in recipe between what you guys are pumping previously?

Yeah. I'll let Mike talk about the design.

The results we're talking about are better than we had forecast coming into the year. So, we'll continue to see if this performance has sustained all of the indications.

It's ours (32:03), it will be. And not only will we have stronger IP90s and IP180s, but we expect the EURs to follow as well.

And in some cases, as I've said, this has actually put us into place where we're facility constrained. We have more well capacity than we have facility capacity and we're looking at what's the most effective way to manage that.

But Mike, maybe you want to talk about designs?

Yeah. You bet, Doug.

We first pumped our tighter cluster spacing design, thinner fluid, and finer grain sand. It was in the Austin Chalk, in the Eagle Ford, and we've since moved that to the Lower Eagle Ford zone as well.

And we've now pumped it in Pipestone. In fact, I think it was within 90 days we had taken that technology, that concept, and moved it from the Eagle Ford to Pipestone.

We've also tested it now on the Cutbank Ridge part of the Montney as well. We pumped now on the Duvernay and in the Permian.

So we're testing tighter cluster spacing, basically taking it down to a half, and now even going less than that as we move to 10-foot spacing in the Eagle Ford. Really encouraged with the results.

Seeing significant improvements in well productivity. And we're (33:21) across all of our plays.

One design in one of the plays is not exactly going to be totally replicated in the next play, but tighter spacing is the key theme and what we're seeing.

Great. Thanks, everyone.

Good morning and thanks for taking my question. So just on the cost structure.

Where do you stand in terms of the process of locking in cost for 2018 and maybe you could comment on that by play? And as a follow-up, is it fair to assume that you're going to be targeting 60% to 70% lock in for 2018 as well?

Yeah. Menno, thanks for the question.

I think the first thing, and we highlighted in a number of places, so I think when Mike talked about supply chain and Reneé talked about managing both price risk and market access risk, we actually believe in optionality. I honestly think some of the mindset about creating long-term firm commitments or building your own equipment or all this stuff is very outdated thinking.

The world changes way too dynamically for that sort of thinking. I think you have to actually create optionality as a way to manage risk because things can change.

Therefore, we use a combination of structures and plans. We're not going to comment about what we're doing on 2018, it's commercial at this point.

But I can tell you we're looking at what's the best way, whether it's in the supply chain or access to markets for products, what's the right mix of firm contracting, creating optionality, and taking market risk because, don't forget, one of the things we like about our business today is we're in multiple basins and the fact that if we find tightness in one place we can rotate activity to another place and still deliver the promises we make to the market because of the character of our portfolio. I know that it makes it harder for people to directly predict each thing we're going to do, but this will create value over time because it allows us to deal with the uncertainty that's inherent in the future, and that is one of the ways we're going to manage risk and maximize value.

So as we start to firm up on 2018, we'll talk about how we're doing it but I can promise we're thinking carefully about what's the best way to secure access to the equipment we need without making unnecessary commitments and making sure that we can have that equipment at what we think is competitive pricing that delivers quality returns.

Okay. Thanks, Doug.

And then moving over to the Montney. Maybe you can just elaborate on what the 50% to 60% bump to IP rates could mean for your Montney type curves and recovery expectations, if anything?

And as a follow-up to that, what is a reasonable expectation for upside to IP rates looking forward?

Yeah. Let me first pick up the piece on the development plan.

I mean, if you look at what's happening in the Montney for us the last few years and even if you look at what's happened since our Montney Investor Day a year ago, back in May of last year in New York, our well productivity keeps improving, the average liquids content dominated by condensate keeps getting higher, and what that means is the amount of capital it takes to deliver on our growth continues to drop and I don't expect that trend to stop. In fact, we have a big milestone today in our Montney program that if you remember when we first announced our growth plan back in 2014, since that time as we've continued to prove up more and more condensate production in the play, we had to add what we called a liquid sub (37:06).

We added two, one in the north and one in the south, and these are front ends to the new plants which strip out largely the condensate. The first of those actually starts up today, adding 3,600 barrels a day net liquids production dominated by condensate for us and that start-up's 10 days early and I think, Mike can confirm, I think it's 7% under budget.

But I think this trend of more and more liquids production for the same gas will continue to improve wellbore productivity. If I flip over into Pipestone for a moment, this is really exciting.

These Pipestone wells, the most liquid-rich of all, actually have higher margins per BOE than in both our Permian and Eagle Ford production, and these are wells with payouts of a year or less. And today, our growth plan only assumes we use and debottlenecking the existing capacity we have, and we're working quite hard to think about where we want to take that asset in the future.

But our five-year plan only assumes we actually do some debottlenecking over the next year and that's it. But with these kind of results, and effectively in many cases these are now oil wells effectively, we're trying to figure out how to develop that.

Mike, trends on completion design in the Montney?

It's a similar story to our Eagle Ford experience. We've been reducing the cluster spacing, going to thinner fluids – (38:39) is the fluid that we've been testing of late – and going to finer grain sands, and we're seeing significant uplifts in our productivity both in Pipestone and Tower.

So, again, really encouraged by that. And I did mention in my review that we're looking at updating the type curves and inventory later this summer with respect to the Montney.

So not a lot more to add on that, though.

Thank you very much. That's it for me.

Thanks, Menno.

Thanks. I had a couple of questions on the cube approach that you're talking about.

Can you highlight for us again what's the tightest spacing you've tested in the Permian? I think you mentioned it was 660 feet.

I just wanted to confirm that.

Yeah. Thanks, Amir.

No, we said it's tighter than that. We haven't disclosed those details yet.

We plan to this summer. And the reasons is we want enough production information.

We've now tested this cube concept three times in the Permian and we'll talk about that. All I did say is it's just tighter than 660s but we haven't disclosed the exact spacing.

Part of that is we have been trading that information with some of the other operators in the basin who have information that we thought would be helpful to us, but we do plan on talking about that later this summer. I would say, and I think Mike may have mentioned this, our biggest pad in the Permian is now 33 wells.

We reoccupied the Davidson pad and added 19 additional wells to the first 14. Just brought that pad on.

Some of the wells have literally been on only a few days and it's already making over 14,000 barrels of oil a day and about 18,000 BOE a day, and it's still cleaning up. I think the longest on production well there has been less than two weeks now.

So, we believe this is the right way to develop stacked pay at scale both to maximize recovery and actually to minimize development costs. So we'll talk more about that this summer.

Okay. And so the optimal spacing, it seems like you'll have that figured out because you don't plan on going back and drilling infill wells?

Is that fair? That's the whole approach with the cube?

That's our objective. We think that there's plenty of data from the older unconventional plays like the Bakken and even the Eagle Ford where coming back in and drilling infill wells, or what people refer to as child wells, shows that you ultimately get less recovery than if you drill that spacing initially.

So that's why, Mike mentioned this back in 2015, I think we drilled the most instrumented vertical well ever done anywhere. And where we drill the vertical it's actually a producing well, and put pressure monitors, I can't remember how many zones, something more than a dozen.

And then we drilled five horizontals by that wellbore at different vertical and lateral spacing. And we used that combined with MicroSeismic to help us understand this.

Then we did the Davidson pad, the original 14 wells. Then we went to Abbie Laine and did a 12-well pad.

Now we've come back and done an additional 19 on the Davidson pad. And we're excited by this.

We think we're figuring this out. And so as we continue to advance development of our Permian position, we could do it in the most efficient way possible.

Sounds good. And when will you be bringing that approach up to the Montney in terms of developing all the zones at the same time?

Is that more in 2018?

We're doing it now. We've started it now.

I think we've got a 16-well pad in the Montney we've just completed. It's the same basic concept.

And as we've been talking about for the last year or so, we've been derisking the stack there and understanding the liquids content in it. But we're taking the same approach in the Montney as we're taking in the Permian.

Okay. And just one final question on the changed or the improved design that you talk about in the Montney.

With the finer sand, are you basically extending the frac line (42:49) or do you feel like you're recovering more of the reserves per section or per wellbore?

Yeah. So, the concept of going tighter cluster spacing, thinner fluids to avoid the content we call (43:08), that's the thicker gels we're creating, as well as those thicker gels are damaging our reservoir.

But with the finer grain sands, we're looking at proppants are near wellbore fracture apertures and having them more productive. So it's about getting more effective new wellbore fracture complexity and having that to offset.

So that's concept behind the finer grain sands.

Okay. Appreciate the color.

Thanks.

Good morning. Congratulations on the strong quarter.

Doug, I just want to clarify your earlier remark. The current 2017 production guidance is not based on advanced completions, and therefore advanced completions potentially represent upside to the forecasts.

Is that correct?

Yeah. Jeff, we had some of this in here but we've been pushing it farther and faster.

I mean, Mike mentioned this, we just have done our tightest per cluster spacing in the company. We just completed our Lower Eagle Ford well at 10-foot cluster spacing.

It's only been on a few days, but it's the biggest well we've ever drilled in our Eagle Ford position just to give you some concept. And that outperformance unfortunately at the moment hasn't translated to its full potential because these wells are actually so strong we don't have enough facility or tank battery capacity to produce them in our existing wells.

Because if you remember, part of our plan for 2017 in both the Eagle Ford and the Pipestone Montney was our drill to fill program, and as we're getting stronger wells we either have to add additional facility capacity which we're not convinced is the right thing to do just to capture some of this early time production or whether it just means it takes less wells to deliver on that program. But, yes, there is some upside in here and we're working to understand that.

And as Mike had in one of his charts, the upside's big. Last year and in 2015 in many ways, the focus had to be on taking cost out and make this business work at today's prices.

As we move to 2017, we felt there were two things we needed to do. We had to continue to drive efficiency to offset inflation because inflation is real but we want to make sure that we didn't see our returns and our margins drop.

We've been very successful at doing that so far. I think that'll continue.

And the second opportunity was to take that same energy we had focused in on taking cost out to now put it into making even stronger wells, and we're now two quarters into that. We think being a very, very good result so far.

And just a follow-up. The idea on the Montney, if it turns out that you can drill less wells to achieve the production to fill the capacity there then, everything else being equal, that should mean that you've filled the capacity at lower costs.

Is that fair?

Yes, and that's exactly right, Jeff. And that's what's been going on for the last couple of years.

Our growth plan in the Montney has really been on the gas side, it's been very consistent since 2014. What's changed is two things.

Number one is the amount of liquids, particularly condensate we're going to produce. And now by the time we exit next year, we'll be producing over 70,000 barrels a day of liquids, the majority of which is condensate and that contrasts to kind of less than 20,000 barrels right now.

So that's very strong growth rate from that. And the second thing is it's taking fewer and fewer wells and those wells are causing less and less to do that.

I mean, this is – as I point out to folks – we're in the two most active plays in North America, the Permian and the Montney, and we're investing in both because of the quality of the returns we generate.

Okay. I'd like to close with just maybe a Mike question, I'm not sure, but first can you identify the five benches that were developed in the Abbie Laine pad and I want to make sure I'm understanding the cube correctly.

Does the cube approach suggest that Permian development will be limited to these five zones going forward?

Mike's just verifying the Spraberry and Wolfcamp. But, no, is the answer to the second part.

It depends where you are in the basin, which benches you're going to be developing. So if you're in the heart of the Midland Basin obviously everything in the Spraberry and the Wolfcamp is working.

We're looking at the Clear Fork as well but if you go north into Martin County, for instance, the Middle Spraberry has become a very successful zone. So it does depend where you are in the basin.

Mike, on Abbie Laine?

Yeah. You bet.

So completed benches is the Upper and Lower Spraberry, the Lower Spraberry for Wolfcamp A, the Lower Wolfcamp A, and the Wolfcamp B.

Okay. Great.

Thanks very much. Appreciate it.

Great. Good morning.

A quick question, just a follow-up, Doug, on the Montney. So how do we think about the sequencing of events here as you get later in the year considering the guidance for gas to be down in Canada sequentially here and in the next couple of quarters and then the start-up of the plants in 4Q.

So is it the initial volume ramps? Debottlenecking existing wells?

Is there a plan for batch completions coming on? Just wondering on the sequence of events that we can expect as we get closer to that big ramp later in the year.

Yeah. Largely, what's happening right now, Steve, were just continued, within the existing gas capacity we have, is how do we maximize liquids until the new plants come online and we have additional processing capacity.

And what you see in that trend is stable to slightly increasing liquids volumes in the Montney while declining gas. We are drilling and completing wells in the Montney today.

We had to start earlier in the year because we use surface water out there and recycled water as our frac water. And if we had a dry summer, we've had a really wet spring, but if we had a dry summer we wouldn't be able to complete all of our wells so we had to start a bit earlier.

But largely, the big ramp happens in the fourth quarter. And what we've said is two of the three plants should start-up by the middle of the quarter.

We're working to bring that forward. They're doing well.

And the third plant will start-up in the first quarter. But it will largely have a fairly big step in the fourth quarter is the broad thing.

And then across the rest of the portfolio, the Permian grows quarter-over-quarter. Liquids across the portfolio grows quarter-over-quarter.

And then gas declines slightly over the next two quarters and then strong growth in the fourth quarter.

Great. Thanks.

And a quick follow-up just in terms of the expectations for what you're talking about, disclosing about inventory in the Permian later this summer. Should we expect, I know a lot of those location counts date back to the acquisition and then I know that you did a little bit of high-grading or premium inventory disclosure last year at Analyst Day, should we expect going forward that you'll be able to give us some clarity on, say, the number of development pads or cubes that you envision or are we still talking about kind of sticks on the map ultimately number of locations per horizon?

Just wondering if you could bound kind of the expectations of what we should be looking for when it comes to that disclosure.

Yeah. We're still working on how to do that.

I think at one level what we intend to do is, if you look at what we do on disclosure today, show by zone, by county what the inventory is. We'll continue to do that.

My expectation is that will grow both from our own activity and from derisking activities others in the play are doing which will benefit from those results. And on the premium side, you'll see things like it wasn't very long ago Middle Spraberry wouldn't have been considered premium inventory; it is today.

I think you'll continue to see those trends. So wells that were in inventory but not premium move across that line.

And then I think spacing below 660 feet for premium inventory we'll also see emerge as we go through this year. I don't think it'll stop this year.

If you look at it like, as you know some operators are putting a lot of attention on the Wolfcamp C right now in the Midland and Upton County area which we're very excited by and we'll learn from and incorporate that, we've done a lot of work ourselves on some other zones. This idea as Mike mentioned of multiple benches in the Lower Spraberry and the multiple benches in the Wolfcamp A and this sort of wine rack development approach is something we've now tested at scale and we're really encouraged by the results.

So I think that this trend will continue over the next few years. And then as Mike said, we're doing a lot of work on completion design, how to get more effective fracture complexity which should mean that we improve recovery and get better type curves as well.

So, a lot of things going on here, but we now think we'll have enough data to talk about the next step in that process this summer.

Great. Thank you very much.

Thanks. Just one follow-up with regards to the Permian with the experience that you now have at the Davidson and Abbie Laine pads.

What is your base case plans for Permian pad development from here and to what degree is land constraint a mitigating factor?

Yeah. Brian, it varies a little bit depending where we are in the basin, but the concept of multi-well pads developing the proven portion of the stack simultaneously using multiple rigs and multiple frac spreads simultaneously is the base case now.

That also allows us to do thing like build these water hubs. We've pumped over 50% recycled water now on our fracs.

So that means we're moving water by pipe to all of these locations. We can build these water hubs which will serve multiple multi-well pads which reduces cost.

And then the reoccupation idea also means we reduce surface cost, facility cost. We've really seen a big benefit of that in the Davidson pad.

So I think that that is the model going forward. And then we can actually use the fact that because we're kind of in all four corners of the Midland Basin, we can also use that to how we think about moving our development around with things like as we make sure we have the electrical infrastructure to produce the wells with ESPs, as we think about our water disposal and movement infrastructure, even access to markets in the way we want.

So we think that that gives us an advantage and allow us to be flexible in that approach.

Thanks. And you may have said this earlier or maybe not.

Is there some average number to put on the average pad that you're looking at will comprise ex reoccupied wells and why new wells?

Well it does vary a little bit, Brian, but it's trying to move up. And I don't have an exact for you, but I think 8 to 16 is fairly common today for us.

In some cases, bigger. But you can imagine like if you're in Howard County, you're going to be focused on the Wolfcamp A and the Lower Spraberry where if you get to Midland and Upton you have more benches.

So the actual number of wells will vary a bit depending where you are in the basin.

Great. Thank you.

Thanks, Brian.

Thank you. This now concludes our call.

Thanks for joining us today.