Ovintiv Inc.

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

Brillon - Chief Financial Officer & Executive Vice President

Greg Pardy - RBC Dominion Securities, Inc. Menno Hulshof - TD Securities Benny C.

K . Wong - Morgan Stanley & Co.

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

Michael P. Dunn - FirstEnergy Capital Corp.

Brian A. Singer - Goldman Sachs & Co.

Terence E. Chung - Merrill Lynch Canada, Inc.

Thank you, operator. Welcome, everyone, to our third quarter 2015 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 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 third quarter results. Mike McAllister, our COO, will then provide some operational highlights, and Sherri Brillon, our CFO will follow up with a discussion of Encana's financial results before we open the call up for Q&As.

I will now turn the call over to Doug Suttles.

Thanks, Brendan, and good morning, everyone and thank you for joining us. Encana delivered a solid third quarter performance.

We demonstrated high margin production growth from our four core assets and took decisive steps to further focus our portfolio, lower cost and proactively manage our balance sheet. Our strategy of a focused portfolio of top-tier high-margin assets that grow our oil and condensate production is really coming together and showing up in our results.

The combination of our focus on efficiency and expanding margins meant that in the third quarter, our upstream operating cash flow was the same as the second quarter even though the WTI price dropped by over $11 a barrel. We are very focused on becoming more efficient.

This quarter we have captured additional cost savings and now expect to generate $400 million of operating and capital cost efficiencies by year end. And we believe that about two-thirds of these efficiencies will continue even if the commodity price were to rise significantly.

We believe that one of the most important drivers of efficiency is innovation. The company has a great history of innovation and we have worked hard to imprint this even deeper into our culture.

Mike will touch on the value this is creating, but we will invest about $65 million this year to leap forward as we call it and find the best answer on important return drivers like well-spacing, targeting completion designs, production control and logistics. Our portfolio gives us a significant advantage since we can multiply the impact of these learnings across our four core assets.

Our efforts in innovation are probably most visible in the Permian. In less than one year, we have established Encana as the leading operator in the play.

In light of the success of our 2015 divestiture program and to maintain the momentum we've established, we have chosen to bring some activity forward from 2016 into 2015. In the Eagle Ford, we meaningfully grew liquids production and reduced well costs.

In the Duvernay, production growth is on track and we are seeing unlevered returns that make it very competitive. We continue to be impressed with the condensate well results in the Montney.

In addition to our work driving efficiency at the asset level, we have also continued to manage our corporate cost structure down. We have driven down our interest expense and administrative cost by over $300 million per year since we launched the strategy two years ago.

You will hear us talk a lot about focus on efficiency, because these factors are tied deeply to value. The combination of disciplined capital allocation with the pursuit of efficiency in all parts of our business is resulting in not only quality returns at the asset level, but will generate quality returns at the corporate level.

We have further streamlined our portfolio with the sale of our Haynesville assets announced in August and the sale of our DJ Basin assets announced in October. Both of these deals are expected to close before year end.

The proceeds from these sales will be used to strengthen our balance sheet and create additional financial flexibility. We continue to proactively manage our balance sheet through this commodity price environment.

Following the closure of the announced divestitures, we expect to reduce our net debt levels in 2015 by $2.8 billion. We exited the second quarter with operational momentum, which continued into the third quarter as we significantly accelerated liquids growth.

We've now achieved our eighth consecutive quarter of liquids production growth. We are on track to more than double liquids production over the last two years.

Our focus on high margin liquids resulted in close to 80% of our liquids coming from oil and condensate. The growth of these high value barrels has positioned us well for next year as we continue to focus on maximizing margins.

Our four core assets are on track to grow liquids by 57% compared to the fourth quarter of last year. Together these assets now make up 63% of our total production and these assets are continuing to grow as we enter the fourth quarter.

We remain on track to meet our fourth quarter target of 270,000 BOEs per day. We are, however, monitoring the ongoing third-party transportation restrictions in Canada to assess potential impact on fourth quarter natural gas production from the Montney.

Now, I'd like to hand the call over to Mike McAllister to discuss our operating results.

Thanks, Doug. Innovation is in our DNA.

Our entire Encana team is driven to capture this value. We understand how continuous improvements are crucial to delivering quality corporate returns.

Historically, the industry has made gradual improvements over hundreds or even thousands of wells. Our approach this year has been to push the limits to find commercial edge as quickly as possible.

It's important to note that we do this in parallel with our ongoing development, not as a separate activity. Encana's R&D is done in the field and is commercial on its own.

The net effect is we are continuously discovering and integrating new concepts to improve capital and operating cost efficiency. When we achieve success in these innovations, we quickly apply them at scale across the asset base.

This approach is something we've invested in this year in particular in our two newest plays, in the Permian and Eagle Ford. As I review Q3 results for the four core plays, I will describe how this approach has improved our current results, and has greatly enhanced the value of our 12,000-well inventory.

The first asset I'd like to speak to you today is the Permian. Our production growth was strong in the quarter at 28%.

We're on track to deliver 50,000 BOE per day in the fourth quarter. The two plots in the right side of the slide surprised me, surprised some.

After only one year, we are realizing top-tier cost, and production performance. This is a direct result of the approach we've taken in the play.

We'll be first in the play to employ simultaneous operations, reducing cost and cycle times. We reduced drill times to fit-for-purpose rigs, well optimizing – well casing and bit design.

In the quarter we have set a record, drilling 3,400 feet of lateral in one day. We established a new drilling cost benchmark of approximately $2.2 million.

Our well spacing pilot pad in Midland County has one of the most sophisticated evaluations of wells in the industry, with 16 pressure gauges, 10 casing fleets across a 3,400 foot vertical section from the Lower Spraberry to the Woodford Shale. This pad gives Encana the only direct and real-time measurement of pressure interference between wells and benches in the Midland Basin.

Our learnings from this pad, combined with the rest of our technical work, has given us tremendous insight into well spacing and optimal frac design in the Permian. This quarter, we ran four horizontal and four vertical rigs, drilling 17 net horizontal wells and 27 net vertical wells.

We averaged a D&C cost of $6.4 million per well, matching our previously announced cost target. This represents a $2 million per well reduction in cost since we entered the play and a 9% reduction since Q2.

We now have 30% of our production tied into pipeline gathering system and are on track for 50% before year end. This will improve our operating margins by approximately $1 to $2 per barrel.

In addition, this also improves our transportation reliability. These improvements in cost and production are generating returns averaging greater than 30% at strip pricing.

As Doug mentioned, given the positive results, we are accelerating $150 million of capital activity from 2016 into 2015, which will result in additional wells drilled and completed by year end. In the Eagle Ford, we've also moved quickly to become a leading operator.

We're on track to deliver 57,000 BOE per day in the fourth quarter. Q3 production was 54,000 BOE per day, up 18% since Q2 and up more than 25% since acquisition.

Through the third quarter, we ran two rigs and drilled 10 net wells. We also brought 29 net wells on production with the start-up of the Patton Trust South facility.

We realized an average Q3 D&C cost of approximately $5.4 million per well, which beat the previous target of $5.6 million per well that we set just last quarter. By increasing the number of fracs per day, our team has reduced the amount of time it takes to complete a well by 40%.

These realized savings will have a permanent and sustainable effect on our cost structure, further improving the value of this asset. We are now targeting $5.2 million per well.

Our Graben wells and Kenedy infill wells represent the bulk of our 600-well inventory. Recent results continue to meet or exceed expectation.

The work with completions design in the Eagle Ford is a great example of how we can move learnings across the portfolio. Our reduced cluster spacing has generated a 50% improvement in production per well over the first six months.

With cost savings of $2.6 million per well since the acquisition coupled with our improved well performance, we are seeing returns averaging greater than 30% at strip pricing. Shifting to the Duvernay, production in Q3 grew to 9,300 BOE per day, up 59% from Q2.

We are on track to deliver 17,000 BOE per day in the fourth quarter. The Duvernay works and it's becoming material.

Our innovation in this play has focused on reducing well cost and increasing productivity. In the quarter, we achieved a new benchmark completion cost of $6.4 million per well.

Our water hub reduced our water handling cost by $1.2 million per well. In the past 14 days, we have brought on five new wells in Simonette.

These wells are averaging 1,200 barrels per day of condensate and 6 million a day of gas at a flowing pressure of 6,000 psi. These top percentile wells are a result of our unique approach of development in this play.

Our approach utilizes dual drilling rigs, dual frac crews, targeted laterals, high intensity completions and our water infrastructure. We get a lot of questions about our returns in the Duvernay.

The two plots on the right show a comparison of Encana's D&C cost and IP30 performance of our Duvernay and Karnes County Eagle Ford wells. The Duvernay costs are higher, but as you can see, the Duvernay wells are more productive.

As a result of this higher productivity and a competitive fiscal regime, we realize the same returns as in the Eagle Ford. As a result, we are seeing returns averaging greater than 30% at strip pricing.

Note these economics exclude the benefits of joint venture carry capital. In the Montney, our Q3 production was 141,000 BOE per day.

We mentioned in Q2, we had experienced some curtailment in our Montney production due to high line pressures on the TCPL system. At that time, impact was fairly limited.

In Q3, we experienced a production restriction of approximately 40 million a day. Note that this production loss impacted gas volumes only.

The curtailments have continued into the fourth quarter. We're following this closely and continue to mitigate the value impact by preferentially flowing liquids-rich wells and curtailing dry gas wells.

In the meantime, we're pleased to report new liquids results from the Tower area, where four new wells are flowing at greater than 500 barrels per day of condensate after the first month on stream. We've also just brought on an additional Tower well, which is flowing greater than 1,000 barrels per day and 7 million a day of gas after three weeks.

This gives us confidence that our growth plans of achieving 50,000 barrels a day by the end of 2018. The two plots on the right of the slide illustrate our growth plan in the Montney.

The growth of liquids in the Montney will outpace the growth of gas significantly. I'd like to point out how efficient this growth is expected to be with the expected production efficiency of about $10,000 per BOE per day.

Industry has been drilling horizontal wells in Montney for over a decade. In the past year, we have doubled the productivity of our wells through increasing frac intensity.

As a result, Montney generates returns of greater than 60%. Note, that this is excluding the benefit of third-party capital.

In addition, this has enabled us to reduce the number of wells in this year's program and reduced our full-year capital outlook by $90 million. This is a great example of the kind of innovation we want to capture today and not years down the road.

I'd like now to pass the call on to Sherri Brillon to discuss our financials.

Thanks, Mike, and good morning, everyone. As Mike highlighted, our operations delivered solid results in the quarter, and the production growth from our core four assets is driving our financial results.

We have delivered significant year-over-year growth in liquids volumes with average production of about 140,000 barrels per day during Q3, up 35% compared with the same quarter last year and up 10% from second quarter this year. Natural gas volumes were down about 30% year-over-year, largely due to the impact of divestitures, natural declines and our seasonal operating strategy at Deep Panuke.

Most importantly, production from each of the four core assets increased in the third quarter and in total grew from 223,000 BOE per day in Q2 to 249,000 BOE per day or 12% in Q3. Third quarter cash flow increased $190 million compared with the prior quarter.

The majority of this increase could be attributed to our $165 million cash outlay associated with the early redemption of our long-term debt in Q2. This redemption is expected to save us about $200 million in interest expense.

We expect our capital at year end to be at the top-end of guidance at $2.2 billion. Mike talked about the money we have spent on innovation and the value we're getting as a result.

Due to the highly efficient results we had in the Montney, we've reduced spending in this asset. As a result of the strong performance in the Permian, we are directing the capital to that asset.

We also anticipate capital recoveries associated with both Haynesville and the DJ asset divestitures. During the quarter, we received $99 million from net divestitures.

Year-to-date net divestiture proceeds totaled $1.1 billion, but are expected to total approximately $2.8 billion in 2015 with the Haynesville sale that is expected to close in November and the DJ Basin sale that is expected to close in December. These divestitures simplify our business and are expected to have minimal impact on upstream operating cash flow because they close toward the end of the year.

Overall our guidance set at the beginning of the year remains largely unchanged with expected performance within the ranges, only our expected DD&A rate has been lowered. We've recently added to our 2016 hedges.

Through a combination of fixed price contracts and three-way costless collars, we now have 56,000 barrels per day of our crude oil production for the next year partially protected at about $60 per barrel WTI based on the current forward prices. Similarly, we now have 395 million cubic feet per day of 2016 natural gas production hedged at a NYMEX price of $3 per MCF.

Please refer to our Note 21 of the financial statements for details on our hedge portfolio. Similar to the first and second quarters, we've recorded $1.1 billion non-cash, after-tax ceiling test impairment charge that impacted our third quarter net earnings.

The ceiling test impairment primarily resulted from the decline in 12-month average trailing commodity prices, and this is a non-cash charge and not reflective of the fair value of the assets. By expanding the margins in our core four assets, we are making the business robust in the current commodity price environment and creating significant upside to improving commodity prices.

Comparing our upstream operating cash flow from Q2 to Q3 offers some insight into this progress. Despite an $11 drop in WTI prices versus the prior quarter, our upstream operating cash flow in Q3 was essentially unchanged at $314 million compared with a $315 million on Q2 on a before hedge basis.

Increased production from our core four assets and lower operating and T&P cost offset the impact of the weaker oil prices and lower production from the other assets. We are exceeding the cost reduction targets that were built into our guidance.

We are now expecting to generate over $400 million of capital and operating cost efficiencies in 2015. We continue to expect that two-thirds of these capital savings are sustainable into next year even if commodity prices rise.

Our drive to increase the efficiency of our business that enhance returns at the corporate level is not just focused upon our field operations. Corporate costs such as interest and administrative expenses have been the center of our attention and we've been successful in reducing these costs by over $300 million per year since we launched the strategy two years ago.

In July, we've aligned our work force with a more focused portfolio. We've reduced our work force by about 40% and our G&A costs by 50% from year-end 2012 levels.

Going forward, we expect our clean G&A, excluding items such as restructuring costs and long-term incentive costs will be about $50 million to $55 million per quarter or about $5 million lower than what we indicated on our Q2 call. Since 2013, our average interest rate on debt is down by 100 basis points due to our debt repayments and implementation of our U.S.

Commercial Paper Program. Combined with our debt reduction, we have reduced our interest expense on debt by a one-third or about a $150 million per year.

Based on current debt levels, we expect that our interest expense on debt will average about $75 million per quarter. Proceeds from our announced Haynesville and DJ Basin sales are expected to reduce net debt levels to approximately $4.2 billion at year end.

Our liquidity is strong. And in July, we amended and extended our revolving bank credit facilities of $4.5 billion, which are committed until July of 2020.

These facilities support our Commercial Paper Program. It is important to note that our asset sales have been driven by strategy to increase our efficiencies and enhance our returns.

The proceeds offers additional financial flexibility. Actively managing our balance sheet, and maintaining an investment grade credit rating is important aspect of our strategy.

We've been very proactive in our efforts to increase liquidity and financial flexibility and we believe that we are well positioned for 2016 and beyond. Our commitment to maximizing efficiencies has set us up well as we plan for next year.

When we combine durable cost reductions with the increased focus in capital allocation and a tighter portfolio, the dollars we spend in 2016 will generate higher returns. I will now turn the call back to Doug.

Thanks, Sherri. It was just two years ago this month that we launched our new strategy.

At that time, we talked about a disciplined focus on profitable growth. We talked about building a business, which works through the commodity cycle.

We talked about a more balanced portfolio of oil and gas, and we talked about our four pillars with none being more important than best rocks. Our third quarter results demonstrate our strategy is working.

The transformation we set out to deliver has arrived. We have a new more focused portfolio that is much more balanced between liquids and gas and our core four assets now have scale, essentially producing a 0.25 million barrels of oil equivalent per day in the third quarter.

And we've achieved this transformation while reducing our debt by about 40%, almost $3 billion. Despite essentially being a brand new operator in both the Eagle Ford and the Permian, we are already performing amongst the very best operators.

We deepened our culture of operating excellence and are clearly demonstrating that innovation is crucial to value creation and a part of our DNA. Along the way, we've made our company massively more efficient.

As we look ahead to 2016, we will build off this momentum. At a minimum, we expect to maintain the scale of our core four assets and we believe we can build on the efficiencies we delivered in 2015.

Thank you for listening. And now we would be happy to take your questions.

Thanks. Thanks, good morning all.

Doug, I wanted to come back maybe just to the innovation and the impact on cost and so forth in a minute, but just wanted to ask a few housekeeping questions. The first is how should we be thinking about 4Q CapEx right now, just given the year-to-date spend and the $2.2 billion budget?

Yes, Greg. Thanks for joining us.

Thanks for the question. I think that as Sherri indicated, we'll come in at the top end of the guidance I think, and there's really a couple of things driving that.

First of all, for example in the Haynesville, we have some non-operating interest there where the operator was proposing wells and giving our divestment. we chose to participate in those wells, and I believe that accounts for about $50 million that wasn't in our original plan and budget.

But it's important to note, we'll recover that money in the purchase price proceeds. So it will show up in the capital line but it will be recovered through the proceeds.

And then secondly, the other big piece here is a combination of the innovation spend Mike talked about. We have spent more than we originally planned this year.

We're going to talk some about that I think probably more before this call is over and then we're going to demonstrate and show some of that out in the field with those who are joining us next week in the Permian. And then lastly, in the Permian itself, we've had as Mike talked about, we've had really strong results this year.

We're really, really pleased that it was just basically a year ago today we took over as an operator in the Permian Basin and yes, I think our cost and well performance are right there with the best and I think some of the things we've done, this vertical monitoring well, Mike sort of briefly talked about, is a state-of-the-art item and we like to talk about our R&D center is actually in the field. You got to wear boots and a hard hat to go, because we do this as part of development.

But all of that together means we'll be at the upper end of range and it should give us in particularly in the Permian a strong start to 2016.

Okay. Fantastic.

So circa $250 million in the fourth quarter or so?

Yes. I think that's in the ballpark.

I'd have to just do the math, but.

Okay. Okay.

Okay. Perfect.

I know Sherri gave some great stuff in terms of I guess how should we be thinking about next year. Can you give us any ideas maybe around CapEx and production or is it just still too soon?

You know, Greg, beyond what I mentioned there at the end, it's a little too soon. We're working that hard right now.

I think that we're targeting this 270,000 barrels a day in the fourth quarter, and as we indicated there, the only issue we see is just how TCPL and their NEB program plays out. It did impact us to the tune of about 40 million a day in the third quarter.

That's the only risk, and of course that's dry gas we're talking about, so minimum financial impact. But as we look to 2016, I think our mindset is we'd like to make sure we at least maintain that.

And then the second thing, I'm very confident our efficiencies will be even better next year than this year. We'll build off the operating performance we've achieved.

But we haven't yet set the levels of capital or production. That's yet to come.

Okay. Perfect.

And then just to come back to the innovation then. You've made some significant strides in reducing D&C costs and so on.

How much is left and how does innovation play into that?

Yes, well I'll hand that over to Mike, but I think what's fascinating and when you look at it, clearly there's been some help from service cost reductions this year. I think our belief is plus or minus those have probably gotten to where they need to go, that fact even in a few places we started to see some cost come up a little bit as some of these companies are trying to make sure they have a sustainable contract price.

But what we have seen is, for instance, days per well continue to come down. I expect that will continue into next year.

And then some of these very innovative ideas like multi rigs on a pad, multi frac spreads on a pad, we actually drilled out plugs on one pad in the Permian and had four coiled tubings units working simultaneously on one pad. That not only reduces cycle time, it also actually reduces cost because of some of those support services.

But maybe Mike, you'd like to add some other thoughts on how you see the performance moving into next year.

Yes. You bet there, Doug.

Hi there, Greg. Yes, we continuously focus on basically every well.

Once we kind of set that standard, we say okay, what can we do to improve more. And each team member has sort of ideas in terms of let's try this in terms of casing design improvements.

We're looking at basically every time a drill bit comes out of the well, we're looking at how do we make that drill bit last longer for the next well. And of course, our fit-for-purpose rigs, which we put into the Permian this year, walking rigs and doing pad drilling, we're able to drive our costs down from $8.4 million per well when we started down to $6.4 million just in Q3 in less than a year.

So it's just an ongoing continuous improvement focus by the team, and it's relentless. And one of the other things that I really loved is that we share these innovations across the corporation real time with our chief organization.

It's pretty exciting and it's got the organization really juiced up.

Great. Thanks very much for that.

Thanks and good morning. So it looks like you didn't drill any wells in the Montney in Q3, but did bring on nine wells with another – I believe it's seven to be brought on in Q4.

So with this in mind, can you just comment on the frac log in each of the four core plays and whether those numbers have been going up or down over the last several quarters?

Yes. First, let me just, Menno, just mention on the Montney.

Mike touched on this. What's happened in Montney is pretty incredible.

I mean, this just shows how innovation never sleeps, if you really get it right in your organization. I mean, we've been in the play for more than a decade and we've probably seen more improvement in performance in the last year than we've probably seen in an entire decade, which just shows the potential.

Effectively what's happened is our well productivity has improved so dramatically, we didn't actually need to drill additional wells. And in fact wells we had drilled, we didn't even complete because we had our facilities full.

And in fact, I think, Mike and Sherri both kind of talked about how we had capital that we expected to spend in the Montney this year that we didn't spend because we didn't need it to keep our facilities full. And, of course, the other big piece here now is the liquids content.

I mean, we're continuing to be amazed that we don't get more questions about these Montney gas wells that are producing 500 barrels to 1,000 barrels of condensate a day. Those are pretty incredible numbers.

They actually sound like Eagle Ford numbers or something, but Mike maybe you want to run through sort of where we are on completions and drill bit uncompleted as we enter the year.

Yes. As we move ourselves to the end of the year, we're looking at about carry-in wells about 45 wells in going into the end of the year.

Yes.

Okay. Thank you.

And then very quickly on the East Coast to Deep Panuke, is the decision to start that back up being driven by a specific gas price, and if so what would that number look like given weak pricing right now?

Yes, Menno, we actually have started up Deep Panuke. So if you've got anything of an operating background, if you shut a platform down from six months, you do have your fingers a bit crossed when you turn it back on that it will run well, but the team did a fantastic job.

It's back up and running. What it's really tied to is weather, but in this case there were some compressor outages on the East Coast which caused gas prices to run in that Boston market, so we decided to bring it on a bit early, but they're pretty volatile this time of the year.

When the weather is warmer, the price drops pretty dramatically and when it's cooler, it goes up. But in what we can do, we nominate gas 24 hours at a time, so we can actually take the production up and down depending on what we see the market-to-market need is, but it is up and running.

I think we brought that up here in the last two weeks.

Okay. Thanks, Doug.

That's it for me.

Good morning. Thanks.

Would you be able to provide a little more color around the activity with accelerated Permian spend in fourth quarter. And how should we think about, how does it impact how we think about next year?

Does this mean it's going to be lower CapEx relative to before the announcement or more on the higher volumes side? Thanks.

Yes, Benny, I think two things have happened in the Permian drawing this capital forward; one is, as Mike talked about, our performance has been very strong, so we're drilling wells faster. I think our fastest well now is about 14 days.

So we're drilling wells considerably faster. And then our original plan basically had is not completing wells in the fourth quarter and that those completions will happen in the first quarter of next year.

When we looked at the performance, we looked at some of the cost savings we've seen elsewhere in the portfolio, we decided to continue with the completion activity in the fourth quarter and continue some drilling activity. But because it's happening late in the quarter and we do have these multi-well pads and things we have talked about before, it takes about two weeks to six weeks for our Permian wells to get to their peak rate.

That's a combination of how they clean up in this managed pressure flow back we do or some people call it a slow back. All of that means most of the production is going to show up in 1Q has very little impact on 4Q.

But what it should mean is we continue to maintain strong performance in the Permian and continue the growth as we enter 2016.

Great. Thanks for that.

And just are you able to provide current volumes across the core plays that you guys are seeing today?

Yes. Don't have that right at hand here, but we can just follow-up with you later.

Sounds good. That's all my questions.

Thanks.

Good morning, and congratulations on the quarter. First question was, I thought the Duvernay cost reductions appear to be industry leading and I was wondering with these results, is that affecting your thinking about capital allocation for the play going into 2016?

Yes. Jeffrey, the Duvernay, what's interesting right now is we repeated our $10 million per well – a well costs now twice.

So we're really confident about that number and, of course, as we're thinking about 2016, we're going to try to drive that even farther down. But what controls the near-term growth in the Duvernay is gas plant capacity.

We're building another gas plant as we speak. It will come on late 1Q.

We've actually got four rigs at the moment running in the Duvernay, which is designed to fill up that capacity as it comes online. We have taken a decision to defer the start of the next gas plant until we see the results of the Alberta government's reviews there going on.

But that won't affect 2016, but it will mean the growth will be a little slower because we'll take that decision after we see the outcome of their current reviews, but we'll have growth in the next year as we fill up this new capacity we're currently building.

Okay. Thank you.

Slide seven shows continued Duvernay savings on water management. Water is also a very important resource in the Permian.

I was just wondering are you attempting to recreate any of your Duvernay water innovation as you build out the Permian?

It's a great question and we are looking at that and we are probably in 2016 going to do some infrastructure around produced water and how we gather and dispose of that. Trucking costs are a big issue for water no matter where you are, and that's what these systems really do save.

But we're studying that hard and I think our 2016 capital plan will have some water infrastructure in the Permian, but the ultimate design we haven't landed on yet, and this is another area where maybe potentially enterprises within the Midstream space decide to play role.

Okay. If I could ask one last quick one with regard to the well spacing in the Permian.

I was just wondering is the effort attempting to prove a specific spacing pattern that you've already decided on or is this a pattern that's going to emerge from the data?

Yes. You know what we've done there is, so I'm an engineer, so the techie side he is going to come out a little bit here.

But we drilled this vertical well with incredible real-time monitoring unit, which we've actually looked at both frac design and frac interference and well spacing both vertically and laterally. And we've learned a ton from that.

I'll be really honest, we're not going to share that very openly because we spent real money to learn it. We have shared that with a few operators where we do data trades with.

So in other words, they bring information to us, we bring it to them. But what it means is, is we have I think much greater insight into where we think spacing and frac design is headed.

We're planning what we call a mega pad next year, which will test this in real time. And we'll probably talk more about that as we talk about 2016 a bit later.

Okay. We'll look forward to that.

Thank you.

Good morning, everyone. Just wondering maybe if one of you could explain for me, the note 22 in your financials on your commitments and contingencies, there's about $6.3 billion for transportation and processing commitments.

And I'm wondering how much of that relates to assets outside of your four core plays. I'm trying to get a sense of I guess how your transportation expense on your gas might be evolving post Haynesville sale as we go into 2016.

Thanks.

Yes Mike, for a whole bunch of reasons, you actually can see in our supplemental that we actually have, we have some detail on our future commitments over time, but we don't break those out for a lot of reasons, including competitive reasons. What you will see is in fact if you look back in time, we've been reducing commitments pretty substantially over the last three years, two and a half, three years.

You see that also in the results of our Haynesville sale. And actually we are talking about in the four plays where we see our transportation and processing headed.

But we don't intend to break those commitments out specifically.

Okay. Thanks, Doug.

That's all from me.

Yeah.

Thank you. Good morning.

Good morning.

You've announced a couple of significant asset sales over the last quarter, and wanted to see where you see the restructuring process, what additional opportunities if any you see for further narrowing the focus. And if you're satisfied with the exposure you have to the big plays or whether you would look for acquisition opportunities.

Yeah, Brian, this is usually where I say something like is this just between you and me. But directionally what we've been doing, I think Sherri briefly mentioned this in her remarks, that the first thing to note about portfolio is it's been driven by strategy.

So, we launched two years ago. We talked about a much more focused portfolio and more balance between liquids and gas.

And that's driven a lot of the portfolio changes both the divestments and the acquisitions in there. And along the way, of course, we've substantially reduced our debt.

And I think it's sometimes surprising to think in 2015 with low oil and gas prices and because of our hedge position coming into the year, we've been living in a $50 world all this year. It's not a world we have to prepare for.

It's one we've already been living in. And because of all of that, what you see is, is we've actually grown our quarter four or will by next quarter or the fourth quarter here, 35% since the fourth quarter of last year and reduced our net debt by about 40% in a $50 world.

So, I'm pretty pleased about that outcome. We like the portfolio we have.

We have, I think Mike mentioned 12,000 well inventory. We've got running room for at least a decade here.

And as we look at the portfolio, we'll continue to look at non-core positions as we always do, but we never actually make specific comments about that and we have done some very minor acreage acquisitions in our plays that are out there. They are not substantial, but they continue to build on the positions we have and we'll continue to look at that in this environment.

That is helpful. Thank you.

And then back to the Duvernay, you talked in the release just a second ago on one of the earlier questions about some of the cost efficiencies you're seeing. Can you also speak and remind us of what well performance is looking like, what you see is a repeatability across your acreage and remind us of expectations and results for production mix at the beginning versus the average over the life of the well?

Yeah, let me hand this over to Mike. He talked briefly about that, but a lot of these wells are plus 1 million barrels, 1.1 million barrel type curves.

They are about half condensate, half gas. Some can be bigger and actually in the Duvernay's case, we actually talk about the north and south Simonette.

The north has a bit lower cost and a bit smaller type curves and the south has a bit higher cost but bigger type curves, because it's much higher pressure. You like that.

You hate it when the combination goes the other direction, but maybe Mike, you just talk about well performance, particularly given that we've basically doubled our producing well count in the past few months.

Yeah. You bet you.

Yeah we actually in the last 14 days here we brought on five new wells in Simonette, and this would have been at Simonette south. And these wells, they're averaging 1,200 barrels per day of condensate and 6 million a day of gas flowing at 6,000 PSI, and we think this puts these wells in the top percentile, the wells that we have on production right now.

So, really encouraged with what the results we're seeing in both Simonette north and south, as Doug mentioned we're a little deeper and higher pressure in Simonette south, so well costs are a little higher, but the well performance is also stronger with the stronger type curve. But really encouraged with the results we're getting out of the Duvernay right now.

Brian I'd just add, one of the thing if you – I don't know if it's up yet but it will be up later today is our latest corporate deck. It has a slide specifically on the Duvernay wells' EURs and basically all the data around the type curve and cost.

That's great. Do you expect the production mix to hold as the well continues?

Yeah, yeah. For sure, we're looking at about 50% of the production being liquids, and the other 50% being gas.

Thank you.

Thanks. Thanks for taking my question guys.

So, my question here is on the Permian. We're seeing a trend here with Permian, some of the Permian competitors drilling longer laterals.

Is this something like you guys are moving towards as well? And can you maybe provide some commentary on the progress to-date and how much of your acreage may be opened to this extension?

Yeah, Terence. I think what you'll find in all these plays and if you look at what we do across all of ours is, we basically try to drill the longest laterals we can, because they are the most efficient way to develop that.

I think we have three wells over 9,000 feet now. Some of this is dictated by your land position and one of the things we do, others do as well is between small acquisitions and trades, you try to actually get where you can drill the longest laterals possible.

So, I would expect as the play continues to develop and mature, you will see lateral lengths continue to grow. I think our type well today, we talk about 7,500 feet, I think not too long ago was 7,100 feet.

So, you can start to see that trend actually showing up and even what we describe as the type well.

Perfect. Thanks, Doug.

Thank you, ladies and gentlemen. Our call is now complete.