Brendan McCracken - Vice President-Investor Relations Douglas James Suttles - President, Chief Executive Officer & Director Sherri A. Brillon - Chief Financial Officer & Executive Vice President Michael G.

McAllister - Chief Operating Officer & Executive Vice President Renee E. Zemljak - Executive Vice President-Midstream, Marketing and Fundamentals David G.

Hill - Executive VP-Exploration & Business Development

Brian Singer - Goldman Sachs & Co. Greg Pardy - RBC Dominion Securities, Inc.

Menno Hulshof - TD Securities, Inc. Robert Scott Morris - Citigroup Global Markets, Inc.

(Broker) Jeffrey Campbell - Tuohy Brothers Investment Research, Inc. David Meats - Morningstar, Inc.

(Research)

Thank you, operator. Welcome, everyone, to our second quarter 2016 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 most recent Annual Information Form and in other disclosure documents filed on SEDAR and EDGAR. I also wish to highlight that Encana prepares its financial statements in accordance with U.S.

GAAP and 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 provide the highlights of our second quarter results. Sherri Brillon, our CFO, will then provide an update of our guidance; and Mike McAllister, our COO, will then describe our operational results.

I'll now turn the call over to Doug Suttles.

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

This quarter, we continued to beat our guidance across our business. The combination of our cost savings, execution performance, and the quality of our core four assets are driving higher returns.

We are reducing cash costs, increasing capital efficiency and increasing production in our updated guidance. Our stronger returns and expected sale proceeds are giving us the confidence to increase capital spending in 2016 to position us for growth in 2017.

We have once again dramatically lowered our drilling and completion costs in each of our core four assets. This builds upon the already peer-leading capital efficiency that we delivered in the first quarter.

This performance demonstrates that our belief in innovation is paying off. The majority of our cost reductions are driven by structural changes to how we execute.

As Mike will touch on later, our approach is more than a series of one-off improvements. We have built a culture in an organization that rapidly puts successful ideas to work across the entire portfolio.

This gives us the confidence that we can continue to make better wells for lower cost. Our focus on relentlessly increasing efficiency appears to be separating our performance from others.

Our success driving these efficiencies has created substantial capital savings relative to our original guidance. We are reinvesting these savings into higher return wells in the core four assets.

We expect the DJ and Gordondale divestitures to close next week, which continues our track record of focusing our portfolio. With these proceeds, we are increasing the midpoint of our capital guidance by $200 million.

The additional capital will be directed to high return wells across the core four plays with the largest allocation going to the Permian. The reinvested savings plus the additional capital will add 50% more wells to our 2016 program for only 20% more capital.

We are also increasing production guidance after adjusting for divestitures. We now expect our core four production to stay much flatter through the year by adding an incremental 13,000 BOEs per day in the fourth quarter.

In effect, we are immediately replacing the bulk of the Gordondale volumes with production from our core four. This is significant because this additional production has a margin that is five times higher than the volumes we sold.

The additional capital activity has an even larger impact in 2017, adding 30,000 BOEs per day to 35,000 BOEs per day, of which about 75% is liquids. These significant improvements position us to grow cash flow in 2017 and means for the second consecutive year in a difficult commodity price environment, we expect to reduce the net debt.

I'll now turn the call over to Sherri to describe our updated guidance in more detail.

Thanks, Doug, and good morning, everyone. We are extremely pleased with our performance this quarter.

As Doug mentioned, we had tremendous progress in reducing cash costs and increasing capital efficiency. In addition, we have also meaningfully reduced future commitments.

On cash costs, we now expect to capture an additional $100 million of transportation, processing and operating savings this year. As a result, we're lowering our guidance for those line items.

Our operating teams have been executing on the initiatives identified by our LOE task force. Successful contract renegotiations that are under divestures have enabled us to further reduce our current and future T&P cost.

Since our February guidance, the Canadian dollar has strengthened from $0.70 to around $0.77. Our cost reduction comes despite this upward pressure, but due to the FX change, we have increased our per-unit G&A guidance by $0.05.

With respect to capital, we continue to be committed to maintaining a focus and disciplined capital program. We are reinvesting the significant capital-efficient saving of about $150 million back into our core four assets.

In addition, we are using a portion of the proceeds from our divestures to increase the midpoint of our 2016 capital guidance by $200 million. As Mike will discuss later, we'll continue to drill some of the most productive and lowest cost wells in the industry.

As a result, our increased capital activity is highly efficient. We posted an updated corporate presentation this morning that details the updated capital rates and wells for each of the core four assets.

After adjusting for the Gordondale divestiture, we are raising our production guidance, and now we expect that our core four Q4 2015 to Q4 2016 decline rate will only be 5%. This is half of which we originally guided.

To put this into context, with the capital program is just over $1 billion, we're holding production in our core four very close to flat. Our focus continues to be on high margin production.

As Doug mentioned, this incremental activity adds 13,000 BOE per day in Q4 this year and 30,000 BOE per day to 35,000 BOE per day next year, of which 75% is liquids production. Crude and condensate are 85% of these liquids.

Each additional dollar spent has been allocated to generate quality returns. While the majority of the incremental capital will be allocated to the Permian, each of the core four assets will see additional activity.

In addition to reducing cash costs and capturing capital efficiency, we have been deliberate in our efforts to reduce our commitment. In the second quarter, we renegotiated our REX transportation contract, reducing our 2016 cash outlay by over $100 million and by $125 million in both 2017 and 2018.

We expect the Gordondale and DJ Basin divestitures to close by the end of July, delivering proceeds of approximately $1.1 billion. These divestitures will reduce our long-term transportation and processing commitments by $275 million and $25 million respectively.

Since we launched our strategy at the end of 2013, we have reduced our long-term commitments by 40%. This will continue to be a key focus going forward.

I will now turn the call over to Mike to discuss the details of our operational results.

Thanks, Sherri. As Doug mentioned, capital efficiency in each of the core four assets has continued to significantly improve.

It's important to point out that while we definitely worked to reduce costs, that the combination of well costs and productivity that is the real driver of returns. Our goal is clear – better wells at lower cost.

One of the measures that we've been reporting on over the past couple of quarters are pacesetter well costs. Our pacesetter is the lowest D&C cost well in the quarter.

We've been focused on driving structural and cost improvements through innovation. We pilot new ideas and quickly deploy the successful ones back into activity.

Because we are active in the best plays in North America, we're able to harness both our new ideas and the new ideas from our peers. The chart here shows the results in our Permian asset.

The blue bars show our average quarterly D&C cost for each of the past six quarters. The green bars show our pacesetter cost from those same six quarters.

Through the application of structured innovation, we carefully analyze our results to understand what parameters are limiting our ability to improve. With these learnings, we test new ideas to improve the next wells' performance.

By rapidly converting successful ideas and transferring them across our portfolio, we can repeat the pacesetter cost performance at all our wells only two quarters to three quarters later. The same pattern is occurring in each of our core-four assets.

We are commonly asked about price recovery. How much of that cost efficiency gain will be sustainable?

Our analysis shows that approximately two-thirds of our cost savings are structural and therefore sustainable. A very simple example is the significant reduction in number of days it takes to drill our wells.

These efficiencies will not be reversed. Starting with the Permian, our newest pacesetter D&C cost is $4.3 million.

We averaged $4.9 million per well in the quarter. This is a $0.5 million reduction from the first quarter and down 30% (sic) [31%] from our 2015 average.

A few months ago, we highlighted our achievements while drilling and completing a 14-well pad. This pad peaked at approximately 12,000 BOE per day gross.

This produced over 0.5 million of barrels of oil equivalent in its first 50 days in production. It only took us 120 days from the spud of the first well to initial production.

The 2016 production efficiency is approximately $20,000 per flowing BOE per day. Our Permian well costs and well performance are among the best, which makes for very strong returns.

Building off of these results, we're adding an additional rig to the Permian for the remainder of the year. We are now the second largest producer in the core of the Midland Basin.

The team is also continuing to work on reducing vertical well requirements. We have completed the 2016 retention program for half the expected cost.

We will continue to look for opportunities to replace vertical drilling requirements with horizontal wells. This is mutually beneficial to us and the landowners.

Our current Eagle Ford pacesetter is just $3 million and this compares to an average of over $8 million when we first entered the play. This pacesetter well cost took us over eight days to drill and was completed with a larger frac intensity.

We signaled last quarter that we intended to ramp up our frac intensity and that would add approximately $400,000 per well. Despite this increase, our Q2 D&C costs were down 38% on average from 2015.

This new $3 million pacesetter at a higher frac intensity showed there are still further cost improvements. Our recent geoscience and reservoir work along with offset well performance has really encouraged us to test the Austin Chalk formation on our land holds.

Therefore, in the back half of this year, we will now be drilling and completing two Austin Chalk wells. We're optimizing our chemical program.

The team has identified over $4 million of savings or approximately 25% of the Eagle Ford's chemical cost. This was achieved through optimizing product volume, identifying lower-cost alternatives, and vendor cost reductions.

Our focus on the base is not restricted to reducing our operating cost structure. We're also finding ways to improve base well performance.

Year-to-date, we've been optimizing our artificial lift systems, installing over 100 (13:42). As well, we have been reactivating previously shut-in wells by removing permanent packers, cleaning out the horizontal lateral, and installing artificial lift.

Our three most recent workovers each resulted in production increases of over 400 BOE per day at an average cost of $350,000. These projects offer very high return and short payout.

Finally, we're also debottlenecking our infrastructure to increase production as well. Once again, we have reduced costs at Duvernay.

Our second quarter average of $7.5 million was lower than our first quarter pacesetter. This shows just how quickly we can convert these cost-reduction successes from pacesetter to average results.

Our average costs are now 40% lower than our 2015 average. This quarter, we set a new pacesetter at $6.8 million.

We continue to drive down costs far below our historic averages. Current costs generated economics exceeding 30% after-tax returns without the benefit of joint venture carry at a $50 WTI and a $3 NYMEX.

As you can see on the chart on the bottom right, half of our Duvernay production was condensate. These volumes travel via pipeline to our three processing facilities.

At these facilities, the production is separated into gas, condensate and NGLs. In Canada, these liquids are separated at a plant.

They are not automatically reported to an individual well in public data. As a result, it is important to correct the public well data to add back the condensate production.

Our latest Simonette South pad is a great example. These wells are outperforming our 1.3 million BOE type curve and half of their production is condensate.

We will now be drilling and completing an additional eight wells at Simonette pad in 2016. In the Montney, activity was focused in our tower area during the quarter.

As a result, we have a $4.2 million pacesetter cost and a $4.3 million quarterly average. This is down 33% from 2015.

As we discussed during our Montney Investor Event in May, we continue to focus on growing our margin. This margin expansion is largely being driven by focus on the condensate-rich acreage.

With almost 6,000 gross condensate-rich well locations, these wells will be the focus of our future drilling. The Montney really has become a condensate play for us.

The average condensate gas ratio of a 2016 program is over 75 barrels per million cubic feet. This is seven times more condensate rich than our current base production.

This focus will continue to drive our margins higher. As well, we are very encouraged on the prospect to reduce tolls on the TCPL Mainline making our Montney production even more competitive.

Shown on the chart on the bottom left of the slide, our latest three wells in Pipestone. After just 45 days, we are on pace to produce 50,000 BOE, of which more than 75% of those BOEs are condensate barrels.

These wells generate impressive returns. We will be increasing our activity in Pipestone the latter half of this year with four new wells to be drilled and completed.

We have a clear focus on liquids development and intend to grow our Montney liquids production to greater than 50,000 barrels per day at the end of 2018. I will now turn the call back to Sherri.

Thanks, Mike. Our second quarter results demonstrate strong operational and financial performance.

As I discussed earlier, we're seeing tremendous progress in reducing our cost structure across the organization. We realized these savings in our transportation, processing and operating costs, and this is evident in our second quarter results where these expenses are down quarter-over-quarter.

This relentless focus on reducing cost contributed to significantly higher operating cash flow in Q2 versus Q1. This is despite the erosion of AECO and NYMEX prices.

We continue to exercise discipline and focus with every investment decision we make. Year-to-date, we have directed 95% of capital through our core four assets.

We are very pleased with the production performance from our core four assets which, as Mike noted, continue to exceed our target. This quarter our core four production made up 73% of our total production.

Strengthening our balance sheet and maintaining financial flexibility continue to be a priority. We expect to use a portion of the proceeds from announced divestitures to further reduce debt.

We also continue to have access with significant liquidity. In addition to about $300 million in cash as of June 30, $3 billion of our $4.5 billion revolving credit facility remains unused.

The unsecured and fully committed facilities are in place until 2020. As we discussed before, we have a single financial covenant on these facilities, debt to adjusted capitalization ratio not to exceed 60%; and as of the end of second quarter, we are at 31%.

I will now turn the call back to Doug.

Thanks, Sherri. Let me wrap by saying that we're very pleased with the quarter.

We have made our business massively more efficient. Compared with the second quarter of last year, our operating costs were down 32%, our administrative costs were down 27%, transportation and processing costs were down 18%.

And our well costs are down 30% to 40% compared to 2015 averages and our debt is lower. Our relentless focus on efficiency built on a culture of innovation are clearly delivering tangible results.

And by making better wells at lower cost, we are generating quality returns from our investments at today's prices. We continue to be incredibly disciplined when it comes to where we invest our capital.

With 95% of year-to-date spending concentrated on our core four plays, we are investing in a program that delivers a rate of return greater than 35% after tax in the current price environment. The efficiency improvements we've delivered have put us in a position to add highly efficient capital to our 2016 program.

With the additional funds coming from the Gordondale and DJ asset sales, we are increasing our 2016 capital program by $200 million. The combination of the reinvested savings and additional capital will add approximately 13,000 BOEs per day in the fourth quarter of this year and 30,000 BOEs per day to 35,000 BOEs per day next year with most of that being liquids production.

Our business clearly continues to get better as we invest more capital into our core four assets. Maintaining scale in the four not only preserves economies of scale and capital efficiency, it also improves our leverage ratios by increasing cash flows.

We are positioning for growth while still improving our balance sheet. For the second year in a row and maybe the two toughest years this industry has seen in decades, we expect to reduce net debt.

We believe that this combination will deliver the most value to our shareholders. That now concludes our presentation, and we'd be happy to take the questions.

Thank you. Good morning.

Good morning, Brian.

Given your willingness to allocate a portion of asset sale proceeds here to increase the CapEx, do you believe the balance sheet and leverage reductions are now sufficient or do you see the need or any interest in additional asset sales or equity issuance to support further deleveraging or further that matter additional acceleration activity?

Yeah. Brian, you kind of outlined how we think about it in your question there.

And we've talked about this several times through the year in that we have a number of levers that we can pull to continue to reduce our debt while growing the core four and of course the best one of all is just drive this efficiency relentlessly. I mean I think as Sherri mentioned, we've added almost $150 million of additional scope without – before we even increased the budget and that drives additional cash flow, which further delevers us.

We also continue to tighten up the portfolio and we talked about the use of proceeds there. So we have a lot of levers to pull, as we look forward; and as we look into 2017, we have to consider where we think the commodity prices are going to be, but there's a lot of choices here, and what we really believe we need to do is actually grow our EBITDA as one of the most powerful levers to reduce our debt, but as I think we've noted on the call, we've now reduced net debt two years in a row, or we expect to end in that place this year.

Great. Thanks.

And my follow-up is on the Permian. I was wondering if you could add some more context to the results that you are seeing at the Davidson well.

You talked about the rate, but certainly one of the things that's important here is the learnings from a communication and depletion perspective. Can you talk to that and the implications that you see for spacing in the Midland Basin?

Yeah. I'll hand that over to Mike.

It's probably a little bit early, but I'll hand that to Mike, but I think the coolest thing Mike kind of touched on it is in 120 days, we went from spudding the first well to a 14-well pad on production, and that quickly reached about 12,000 BOEs per day and we drove our cost down considerably through that process. But I don't know – I think it may be a bit early, but Mike, thoughts on well spacing?

Yeah. It's kind of a little bit early, Doug.

One point I wanted to make on that pad is that we, from the first well that we drilled on that pad, talking about accelerating learnings to 17 days, 17.5 days. By the last well, 14th well, we were down to 13 days.

So, that really acceleration of learnings just shows the pad can support rates. Brian, as you saw in the box well and some of the other work that we showed during our Investor Day in the Permian last December, we've been really monitoring and understanding pressure communication by the cost downs between our offset wells.

And the results to-date are as predicted. Probably the best way to say it, we're still watching, it's still kind of early days in terms of production, but we're very encouraged with the results we're seeing.

Great. Thank you.

Yeah, thanks. Good morning.

Doug, the $200 million number and then the 30,000 BOE a day to 35,000 BOE a day into next year, an impressive number. You touched on the reinvestment savings kind of attached to that number.

Could you quantify that a little bit? And then just in terms of how you're going to spend those dollars, then is the game plan in the Permian just to continue on with very large pads as you've done?

Yeah, Greg, I mean, the simplest headline of this, which is that we're actually going to increase activity or scope of our program, in other words the number of wells we drill and complete by 50% over our original plan that we guided to in February for only 20% increase in capital. And, of course, these new wells are coming at these very, very highly efficient cost.

About 80% of that capital is going into the Permian, but – and I think as Sherri and Mike mentioned it, we have capital going into all four. They're all very, very competitive and they all generate quality returns at today's price deck.

So, we don't require better pricing to do that. So, that's the broad shape.

And it's interesting, if we didn't increase scope, we've gotten to the point that we drill these wells so fast, now we would have basically been – had to shut our activity down in the fourth quarter because we would have fully consumed our original scope almost a full quarter earlier. And what we're effectively doing now is that we're going to add one net rig is all to the program to get this additional scope, which may have, as some people think about, the service sector may have some implications there.

But maybe the last point I'd make is it wasn't very long ago we thought as a rig year in the Permian is delivering about 12 wells, now we think a rig year is 25 wells in a rig year as we go forward. Big and small pads, it's a mixture.

But like our Davidson pad, our 14-well pad, we expect to reoccupy that pad next year. We think that that pad may ultimately have 64 wells on it.

Okay. Okay.

So, maybe let me ask the question another way. If you sort of think about like a normalized capital efficiency in the Permian, would $15,000 to $20,000 of flowing sort of be the number?

The math obviously with $200 million in 30 – even using the midpoint, like I think we're at $6,000 of flowing, which is a wonderful number. I'm just wondering if that's fully loaded or not.

Yeah, Greg, good question. Your $15,000 to $20,000 is a good number because what you're missing in that is, we obviously have what we call carrying capital.

Some of those wells won't be completed until next year because we're just drilling this year. So, when you add that back in, you end up in that $15,000 to $20,000 range in the Permian.

Okay, perfect. Just one quick one on the $1.1 billion of proceeds coming in on the DJ and the Gordondale.

That was just like just a little bit below what we were expecting, but there was nothing that really changed in that deal, right? It was $900 million with a face value less I guess working capital and other adjustments, but there was no other changes there, were there?

Yeah, Greg, we have kind of – this is a – this deal has obviously taken a lot longer than a normal deal, we'd openly acknowledge that. And we haven't – and obviously haven't said a lot about it since way back in December.

But after you make the adjustments on this one in the Gordondale deal, we actually, we gave this number. And we normally don't talk net proceeds because it gets very complicated and all the adjustments that come into place.

But in this case, there was a lot of interest so we thought we would just clear the air and say, guys, here is what we expect is net proceeds, so as you look at our balance sheet going forward you can account for that.

Okay, perfectly – perfect. You touched on – just on the TransCanada Mainline Tolls, Brian probably should have asked this question given all the work he has done on it, but just any update there on that in terms of either timelines or what have you, it's obviously pretty important for you guys I would think given your gas volumes.

Yeah, let me ask Renee Zemljak, who is our EVP of Midstream and Marketing, to touch on that. We have obviously been actively involved in that.

I should actually do what you just did. I think Brian's report on that was pretty insightful, by the way, folks haven't seen that, but Renee?

Sure. From a timing perspective, that's difficult to answer.

I can tell you that we are in ongoing conversations with TransCanada. We're really encouraged to date with regards to how those have gone.

Their public offering on tolls has been about a 50% reduction in exchange for longer-term contracts and it's getting a lot of attention and a lot of interest from other producers as well. I am – but it's really difficult to me to comment timing on when we think that will actually come together, but I can tell you that we're encouraged with what we're seeing so far.

Okay, great. And – go ahead.

Yeah, Greg, I just want to add one more thing. We covered a lot of this in the Montney Day back in May, but we believe in this recipe to make money in gas in North America uses a lot of it.

And the good news is by the way, demand is increasing, which we're encouraged by. But this combination, if we've got to be in great plays and great plays are defined by a lot of resource, inexpensive, highly productive wells, and you need scale.

So you can get efficiency and you actually need condensate, and Mike kind of pointed to that the wells we're drilling now have seven times as much condensate per million cubic feet of gas as the old wells. And then we believe we can go head-to-head with this adjustment to the tolling structure with gas from anywhere into the new markets in the East.

Very good. Last one from me then.

I am not sure you'll answer it. But lot of moving parts in the company this year between dispositions and obviously the acceleration activity.

Could you give us an idea where you think you'll exit 2016 oil and liquids corporate? Like is 120,000, circa I don't know 125,000 kind of ballpark-ish because I guess the key is, we're trying to get a sense as to what you're going to look like in 2017, right now it's still a little bit opaque.

Greg, I just don't have that number at hand at the moment, so I can't give it precisely beyond what we've – I think Sherri mentioned, which is we cut the exit rate decline and exit rate we consider as the fourth quarter rate from 10% to 5%. And we are looking hard at what we want to do in 2017, but between lowering our cost structure which is generating additional cash flow in these incredible capital efficiency gains, we're pretty encouraged, but you might follow up with Brendan and the team on that after the call.

Will do. Thanks very much.

Thanks, Greg.

Thank you, and good morning. So I'm just going to follow up with some of Greg's line of questioning.

So, of the $200 million in incremental capital and then reinvested savings, how much of that would be going into new wells versus your DUC inventory?

Yeah, Menno, the actual number of completions we're carrying into 2017 is, I think, only different by like three. So it's really no change to as you think of DUCs.

For us, it's effectively. We've never been sort of – we've never been build-the-DUC inventory believer.

So our pace really doesn't shift at all. I think it went from 31 DUCs to 34 DUCs or something.

Okay, thank you. And then you also mentioned that you're going to be drilling two Austin Chalk wells before year-end.

So maybe you could just comment on how extensive your Austin Chalk – how prospective the Austin Chalk would be on your lands based on what you know today?

Yeah, Menno, it has been some great work by some of our peers in the Austin Chalk. We've been following that quite closely, done a lot of geoscience work around it, and think that the Austin Chalk potential doesn't lay on across all of our lands, but a reasonable portion of them.

And based on our understanding, we think we understand the difference between where you make a good Austin Chalk well and a poor one, and it's now time to go test that and verify that. So, that's what we're going to do.

So we'll have a couple of wells here drilled shortly and, by the end of the year, should have some production results to talk to and at that time, we'd probably have a better feel for how big the potential might be. We don't carry – in the inventory numbers you see for us in the Eagle Ford, we don't carry any Austin Chalk wells.

Okay. Perfect.

And then I've got one final one on the Duvernay. You mentioned that you just drilled a pacesetter well of – I think it was like $6.8 million, so was there any meaningful change in the design for that well relative to what you've been doing for the last couple of quarters?

I'll ask Mike to pick up on it, but we really want to push this point hard because there's a couple of things in what Mike did. Some people have been pulling public data and unfortunately they probably don't understand Canada public data and they are missing the plant condensate, which is the main reason we drill these wells.

So we're really stressing, look, these wells that used to cost over $20 million apiece are now under $7 million. The type curve is 1.3 million BOEs.

These are 50% condensate wells. If we go run the math at the current strip pricing, you will find the returns are very, very good, but some people seem to have missed that.

Mike, maybe you want to comment on how we – what we've been doing to drive the well cost down.

Yeah. Hi, Menno.

Yeah, in the Duvernay as in all of our plays, we can go with multi-well pads. As well in the Duvernay, we've run, to drill an 8-well pad, we'll run two drilling rigs and then dual frac spread, so that's really helped us drive our cost structure down.

With respect to this well, it's just continuous learning. We call it kind of structured innovation.

As we walked along the path, we look at what are those parameters, as the drill bit design is at our bottom hole assembly that's inhibiting the progress and our ability to drill that well faster. So just continuous innovation walking along that path and we do that essentially in all our plays and you can see the results how the costs are coming down.

Okay. Thanks, Mike.

That's it from me.

Thank you. Doug, I think you answered my first question, but just to confirm, you'll end the year with about 34 DUCs.

Is that what you said?

Yeah. That's our current estimate, and the old number was 31 DUCs.

So it's about the same as you saw before.

And most of those are in the Permian?

Most of them, I think we'll have some in the Duvernay as well.

Okay. And then just on the revolver, I know you're paying down debt as we go through the year, but you'll still probably have over $1 billion drawn on your revolver and I know you're not anywhere close to violating the covenant on that.

But how comfortable are you in carrying a significant draw on that revolver and how do you look at that going forward as far as wanting to pay that down or just converting that to straight-out debt at some point?

Well, you know Bob, if you look at our debt structure, and Sherri will want to jump in here, but if you look at our debt structure, about three-quarters of it's due past 3030 – 2030. 3030 is really far out there.

It's after 2030. And actually having some pull on this revolver has given us more flexibility than we had before because otherwise if we retire debt, we were having to accelerate long-term notes, which isn't particularly efficient.

But ultimately, we do want to bring this down, but we've got a lot of capacity. We're not at all worried about getting outside the covenant.

We got about two times cover off that. But Sherri, your thoughts?

Yeah. I mean considering that we don't have a maturity until 2019 and that maturity is about $500 million in that year, when I look at the revolver the reason we have such a strong revolver is to utilize it during these cycles and through these times and we're confident that we certainly want to exceed our covenant and I think it provided us with the financial flexibility that we required in order to get through this cycle.

Okay, great. And last question just quickly.

I know you've got several other – most off your other non-core assets you're trying to sell. Don't recall how many of those currently have data rooms open but how many of those are there bids due during the second half of the year that we might anticipate that we'll see something on further asset sales in the second half of 2016?

Yeah. I almost feel like saying good try, Bob, but we just don't guide to divestments, but the direction you're pointing to is correct, which is we still do have non-core assets.

We've been pretty consistently for two and a half years tightening up the portfolio and successfully at that. But we just believe it's best to build this business around, if you will, the organic existing business and not guide to divestments and talk to them once we have a purchase and sale agreement in place, as we think it's the most efficient way to divest properties.

Yeah, understood. Good quarter.

Thanks.

Thank you.

Good morning and congratulations on all the operational strength that you're showing in this quarter. I was wondering if we can just kind of flesh out the Davidson a little bit more.

How does the – I mean it sounds like a really big pad. How does the size of the pad compare with industry norms?

Which zones are you producing at present? What's the average lateral length of these wells?

And more than anything, is this an evolving prototype for your near-term development in the Permian?

Yeah, I think I'd start with your last part of your question, which we actually believe strongly that these big pads are the most efficient way to do development. So on this pad, it is physically large because we actually had four drilling rigs on it, drilling simultaneously, and then when we did the 14 – completed the 14 wells, we did it with four frac spreads operating simultaneously when we were out there, and we think not only does it shorten cycle time, it drives additional efficiency, so we do think this is the model.

As we go forward, we ultimately think this pad, I think, is probably going to have 64 wells on it. And Mike, maybe you can talk about lateral length in the zones we are developing currently.

Hi, Jeffrey. Yeah.

Lateral lengths averaged around 8,400 foot and it was both Wolfcamp A and Wolfcamp B were drilled into 14 wells.

Okay. Great.

And I assume – well, maybe I shouldn't assume anything. With all the other locations you are talking about, does that imply that you haven't exhausted all the As and Bs that you can drill, and are we talking about Lower Spraberry, any color there?

Yeah. What we've done here is a couple of things and this was one of the previous questions.

We did a lot of work last year with what we call the box well where we drilled a vertical well and then drilled five horizontals by that well at different vertical and lateral spacing, so those were all development wells and the monitoring well was a producing vertical well at the same time. But what we've done now is applied what we've learned doing that work to this Davidson and we think it's the ultimate spacing.

We think we understand frac geometry on this. We haven't disclosed all those details because we've obviously spent a lot of money learning all this, and we are not going to give that away to our competitors.

We do trade some of that information when others have information to trade. So we think that's the case, and then there we also have – we haven't done the Lower Spraberry here at all.

There is Wolfcamp C, so there's considerably more potential and that's how we see that this pad could probably ultimately end up at 64 wells.

Okay. Great.

And my other question I'd like to ask is you've given us a very good roadmap on the Montney through 2018. And you've also highlighted the costs and the attractive condensate in the Duvernay.

So I'm just wondering if we can speak broadly to what variables will determine the extent to which the Duvernay will be able to attract capital over that same 2017, 2018 time period that you've identified for the Montney?

Yeah. The big challenge on the Duvernay, Mike mentioned we have three gas processing facilities there today.

We currently have a bit of available capacity, but to grow it substantially beyond where it is today would require building new facilities in that, and we have to just think when we're focused so much on capital productivity, because there is about a two-year cycle time on that, and ultimately probably our preference is not to own the midstream, maybe to do something similar to what we did in the Montney. So, that's really the limiter.

It's not the well economics. It's the lead time to build gas processing.

So I do expect us to continue to invest money there, but it'll probably be largely to fill up and then keep full the existing facility in the near term.

That was actually what I was thinking, too. Can you replicate the third-party capital model for processing that you're going to do in the Montney?

I mean do you think that's feasible over time?

Yeah. I'm looking across the table at Renee, and I think so.

We actually have thought about this several times, but we thought the play need to get a bit more mature before that happened and obviously I think the play is accelerating now. So hopefully that will be available to us in the future.

Okay, great. Thanks a lot and congratulations again on the quarter.

Thank you.

Hey, guys. I am looking on the math on the Permian slide here in your deck.

It's a little hard to tell the scale, but is your acreage in this area contiguous enough to support very large pads on a widespread basis like the one you brought on this quarter? And do you have any interest in doing acreage swaps with other operators to enhance this?

Yeah, David, a bunch of it is and is able, but not all of it, as you can see from the math. And we've been very active this year in doing acreage swaps to make our lands more contiguous.

It's been a pretty active program and we expect that to continue going forward. But you're exactly right.

The more we can make it more contiguous and more efficient, we can do the development. So we have a lot of the land we can do that on today.

I mean, David, about how many swaps have we completed this year in the Permian?

I think about five swaps and multiples more underway.

Yeah. So we're headed the same way you're asking.

Okay, fair enough. And on the same slide, you have a little bit of color on the Clearfork and the Canyon.

What's the timeline on testing these new zones?

Let me toss that one over to David. Timeline on the Canyon, and what was the other zone you asked about?

The Clearfork. You have them both highlighted there as upside zones.

I was just...

Yeah. The timing for testing?

Yeah. Those zones and several more of that, the teams have continued to do work on core work, simulation work, but we're just not disclosing exactly the timing.

We'll be testing those, but the teams are active in that.

All right. Thanks a lot guys.

All right. Thank you.

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