Nov 3, 2016
Executives
Brendan McCracken - Encana Corp. Douglas James Suttles - Encana Corp.
Michael G. McAllister - Encana Corp.
Sherri A. Brillon - Encana Corp.
Analysts
Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.
Michael P. Dunn - GMP FirstEnergy Josh I.
Silverstein - Deutsche Bank Securities, Inc.
Operator
Good day, ladies and gentlemen, and thank you for standing by. Welcome to Encana Corporation's Third Quarter 2016 Results Conference Call.
As a reminder, today's conference call is being recorded. At this time, all participants are in a listen-only mode.
Following the presentation, we'll conduct a question-and-answer session. For members of the media attending in listen-only mode today, you may quote statements made by any of the Encana representatives; however, members of the media who wish to quote others who are speaking on this call today, we advise you to contact those individuals directly to obtain their consent.
Please be advised this conference call may not be recorded or rebroadcast without the express consent of Encana Corporation. I would like to turn the conference call over to Brendan McCracken, Vice President of Investor Relations.
Please go ahead, Mr. McCracken.
Brendan McCracken - Encana Corp.
Thank you, operator. Welcome, everyone, to our third 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 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 provide an overview of Encana's financial position before we open up the call for Q&As.
I will now turn the call over to Doug Suttles.
Douglas James Suttles - Encana Corp.
Thanks, Brendan, and good morning, everyone. Thank you for joining us.
We delivered very strong financial results during the quarter, which were driven by exceptional operational performance and continued capital and operating efficiencies. We are off to a great start on the plan we laid out just last month.
Productivity and cost are already running ahead of the benchmarks we used in our plan. Our results this quarter demonstrate our ability to deliver quality returns and leading cash flow growth.
Our cash flow in the quarter was 26% above the consensus expectation. We continued our track record of operational excellence, efficiency and active balance sheet management, and we expect to meet or exceed our 2016 guidance.
Before we get into the details of our quarterly results, I'd like to take a minute to recap the key elements of our five-year plan. Encana's growth potential is second to none amongst our competitors.
We expect to grow cash flow by more than 300% over the next five years by both increasing production and, more importantly, increasing our margins at a flat price stack. We expect that by the end of 2021, we will grow total company production by over 60%.
This growth consumes a fraction of our 2,000 premium return inventory locations. These are wells that deliver at least a 35% after-tax rate of return at a flat $50 WTI oil price and a flat $3 NYMEX gas price, which translates to a corporate return in the mid to high-teens.
We also expect our corporate margin to double at the same time. This is the total company margin.
We focus on this because our investors can't buy a half-cycle well return or our asset level operating margins. These are important indicators, but our investors can only buy our all-in corporate returns and all-in corporate margins, and this is what we are focused on increasing.
This margin expansion is primarily driven by our shift to high-value oil and condensate in our core four assets. The combination of production growth and margin expansion leads to tremendous cash flow growth and a capital program that is self-funding post-2017.
Our five-year plan is based on second quarter 2016 cost inefficiencies (4:33). Mike and Sherri will describe later how we are already running ahead of these Q2 benchmarks.
We expect to continue driving down costs and improving productivity. This would represent an upside to our plan.
We have worked extremely hard over the last three years to improve the resiliency of our business. We are now ready to realize the growth potential of our world-class asset base and deliver quality returns to our shareholders.
We continued to build on our track record of operational execution during the third quarter. Cash flow in the quarter was $252 million.
This result was driven by our operating efficiency and continuing to increase our margins. Our expectation for full-year 2016 operating, transportation and processing cost is now $150 million less than our original guidance.
We demonstrated improved well productivity with precision targeting of our horizontal well bores and by optimizing our completion designs. This quarter, we saw these innovations make superior wells in Glasscock County in the Permian, in the Pipestone area of the Montney, and both the lower Eagle Ford as well as the Austin Chalk in the Eagle Ford area.
Mike will show how our latest well designs are significantly outperforming type curve in each of these plays. We also matched or beat our second quarter pacesetter well cost in each of the four core assets.
We now have drilled and completed a 7,500-foot Permian well for $4.2 million. This quarter, our average D&C cost in the Permian and Duvernay dropped again, this after some already impressive reductions earlier in the year.
As Mike will show, there is a select group of companies making the best wells in the Permian. There is also a select group of companies making the lowest cost wells in the Permian.
There is an even smaller group of companies that are doing both, and I am pleased to say that Encana is part of that very select group. Recall that last quarter we announced that efficiency gains in our capital program this year had enabled us to increase our well count by 50% for only 20% more capital.
We are on track with this program and expect to reduce the decline of our core four assets to 4%. This is down from our original expectation of 10%.
We've now reduced our net debt to $3.4 billion. This marks the second year in a row where we've made substantial reductions in our debt.
We've now cut our debt in half since year-end 2014. We have over $5 billion in liquidity, which gives us the confidence to fund our 2017 capital program.
We get asked a lot about our ability to ramp up activity without increasing cost. Mike will describe in more detail why we expect to maintain or reduce our well cost.
We are experienced at efficiently executing large capital programs, and this is something that we have prepared for. We are currently running 12 rigs across our business today.
We expect to be at 14 rigs by the end of this month. This is close to the 15 rigs we expect to run through 2017.
In the Permian, we are currently at four rigs and expect to add the fifth rig before year-end. We expect to run approximately five rigs in the Permian in 2017.
Now I'll turn the call over to Mike, who will provide some of our operational highlights for the quarter.
Michael G. McAllister - Encana Corp.
Thanks, Doug. Earlier this month, we gave a comprehensive update on our four core assets.
Today, I'd like to give an update on our progress this quarter on maximizing capital and operating efficiency. We've been consistent for some time, pointing to the importance of efficiency as a key driver of value and returns.
This means getting the best wells for the lowest costs. I'm pleased to say that in our first quarter since we laid out our growth plan, we are already running ahead of the efficiency we built into that plan.
We believe there are four critical elements to the process of increasing productivity and lowering costs. It starts with levering our portfolio advantage.
Our acreage is in the core of the best plays. Being in the best rocks is crucial to efficiency.
We also use our multi-basin position to be on the cutting edge of our industry. We can rapidly deploy successful ideas and practices across our four assets.
The second step is our innovation process. We believe strongly in learning while doing.
Our teams are constantly looking for new ways of executing our work. The third step is continuous improvement.
As we showed at our Investor Day, we are among the very select group of operators that have both the highest-performing wells combined with the lowest costs. We reached this leading position in all four assets by making better wells for lower cost quarter after quarter.
Our experience tells us we'll continue to become more efficient. The final step is competitor benchmarking.
Our acreage position in the core of the best plays means that we're levering the learnings from our competitors. We're very deliberate and intentional about this process.
We tell our teams all the time: it doesn't have to be our idea to be a good idea. This entire process is underpinned by our culture of one, agile and driven.
We pride ourselves on being on the fast-moving end of the industry where improvements implemented quickly add up to big gains in performance. We are relentless about meeting and beating our targets.
We focus and act as one team with one common goal. As I mentioned earlier, we believe it all starts with being in the best rocks.
This slide shows our leading acreage position at each of the four core assets. Being in the best rocks is one of the pillars of our strategy.
Our geoscience and engineering workflows have been critical to building this portfolio. The 10,000 premium return locations that we have identified across the portfolio are the foundation of both our current results and leading cash flow growth over the coming years.
Here's why the combination of having core acreage and being a leading operator matters. The data on the graph shows the cumulative production for 20 operators that dominate the Midland Basin.
The data includes all the wells since 2014 that have reached 180 days of production. We believe this is a crucial dataset to understand the relative value of the Permian today.
There is a defined break between results from the core in the basin to the non-core, where the core wells are a magnitude larger. Even within the core, there's a 40% spread from the highest to the lowest productivity.
As Doug said earlier, there's a select group of companies with leading well performance. This is a direct reflection of operations excellence.
Our leading performance in the Permian is a direct result of leveraging our multi-basin portfolio. Our average IP180 of over 500 BOE per day is amongst the best performers in Midland.
We believe IP180 is the best productivity measure to indicate relative value and returns. It provides a balance between more shorter-term production that can be noisy due to operating constraints, but also relatively timely and doesn't mean waiting years to figure out if a well is good or not.
On the next slide, I'll describe how we are optimizing our completions further to improve our well performance. In order to get the leading results, we are focusing on making stronger and stronger wells while continuing to be cost leaders.
We are currently focused on three technical drivers of performance. The first is precision targeting.
By using our extensive data library, our geoscience team has constructed a 3D model of the Permian. By utilizing this during the drilling of the well, we land the horizontal section exactly in the best rock.
This maximizes well deliverability before we even start to complete the well. The second is frac geometry.
Through learnings from our experimental box well, we have optimized the completion size and spacing to minimize interference between wells and maximize drainage. The final step is in the details of the completion design.
Back in 2015, we ran multiple wells at up to 4,000 pounds per foot. This year we've been using 1,200 to 1,800 pounds per foot, The Glasscock wells shown here were completed at 1,500 pounds per foot in 50-foot cluster spacing.
By systematically improving our completion design, landing in the best rock and maximizing drainage, we're creating the next generation of wells with much higher productivity. During the quarter, we brought on five net wells in the Permian.
They're all meeting or beating expectations. This included two new wells in Glasscock.
These wells have been flowing for about 90 days. They are on pace for strong IP180s at about 30% above type curve.
I'm pleased to report that we overcame our production curtailment of 2,000 barrels per day of oil on our RAB Davidson pad, related to an offset operator frac operation. This pad is now back to full production.
Being a multi-basin company, we are continually pushing the envelope in all of our core plays. We take learnings from one basin and rapidly apply them to other assets.
In the Eagle Ford, we are currently executing a new completion design. Utilizing thin fluid with cluster spacing tighter than 25 feet, we are creating a complex fracture system that is substantially increasing productivity.
Here you see three new Lower Eagle Ford wells that came on during the quarter using this design. We pumped about 2,400 pounds per foot on these wells and saw no stress shadowing overwhelming any of the individual fractures.
This means all fractures are equally contributing to the well. These are early results, but through the first 30 days, we're seeing a 125% increase in productivity.
We talked briefly about our recent Austin Chalk results during our Investor Day a few weeks ago. We've built our understanding of the reservoir and it shows within the performance of our first two Austin Chalk wells.
With IP30s at 2,000 and 3,100 BOE per day, these are two of the best wells drilled by Encana this year. At an 80% oil cut, these two wells combined have produced over 100,000 barrels of oil in 30 days from a total of just 7,000 feet of lateral.
This map shows the top Austin Chalk wells recently drilled in Karnes County. Our 8H well has one of the highest IP30s in the Austin Chalk to date.
We're in the process of updating our inventory and expect to add at least 100 locations to our Eagle Ford inventory. Note that we previously had zero Austin Chalk locations included.
We also expect to spud at least three new Austin Chalk wells before year-end. We are maximizing capital productivity by utilizing our existing Eagle Ford facilities for this program.
In the Montney, we have continually improved the well design over the past decade to progressively make better wells. Recently, we've made a step change in well productivity.
You can see we've achieved up to a 55% uplift in IP180. Increasing productivity increases our margin.
We're also significantly increasing our Montney margins by focusing on condensate-rich locations. During the quarter, we brought on several new Pipestone wells.
At the Investor Day, we highlighted two wells with an average IP30 of 900 barrels per day of condensate of a total 1,400 BOE per day. Since then, our two most recent Pipestone wells have passed 30 days of production.
These two wells are even stronger, with IP30s of 1,200 barrels per day and 2,400 BOE per day. Next year, we expect the CGR of our Montney program to average at least 85 barrels per million.
This is greater than eight times more than our historic Montney average that was under 10 barrels per million. We see a 30% compound annual growth rate on our Montney liquids through 2021, as illustrated in the bottom right corner of the slide.
At $55 WTI, the $3 NYMEX price, our premium well inventory operating margin averages $14 a BOE. As you can see, innovation is playing a key role in increasing our well performance.
Now let's look at the role innovation is playing in lowering our costs. We have had yet another quarter of D&C cost reductions, with new pacesetters being achieved in both the Permian and Duvernay.
Average D&C costs in the quarter were also another step lower. The $4.2 million pacesetter in the Permian is almost 40% lower than our 2015 average and a sign of further cost reduction opportunities within the play.
We also repeated pacesetting activity in both the Montney and Eagle Ford. In the Montney, Pipestone D&C costs now average $4.4 million per well.
The economics for these wells just continue to improve. We often field questions around how sustainable our well costs are if activity picks back up.
Since 2014, over 70% of our well cost reductions are structural; therefore, are sustainable. The remaining 30% savings are a benchmark against 2014 service costs.
While activity is picking up, we're still a long way from 2014, when oil was $100 a barrel. We're managing the risk of inflation by using our scale and multi-basin portfolio to our advantage.
This enables us to move services around between assets and unbundle the supply chain. The largest cost driver in our completion costs are water and sand at 60%.
Our work with brown sand is showing no performance degradation compared to white sand. This is important because the largest single cost of sand is logistics to the mine and transporting it to our location.
Brown sand can be sourced closer to our operations at lower cost. This is just one example of why we are confident in our ability to continue to drive more structural cost savings going forward.
Improving costs isn't just limited to drilling and completions. We're also continuously improving our operating costs.
The only way to stay in a leadership position is to keep improving. Standing still is falling behind.
Last fall, we kicked off the multi-basin task force to identify and rank opportunities that would lower our operating costs. We targeted a 20% reduction in our operating costs over two years.
I am pleased to say that we have already achieved that 20% reduction after only one year. This is another example of how we are able to move expertise and innovations across our portfolio.
Our teams have lowered our costs for water hauling, trucking, artificial lift, workover and chemicals. We expect to continue driving down operating costs across all of our plays.
As a result of these savings, we once again are lowering our full year 2016 operating expense guidance down, to $3.90 to $4 per BOE. All of these savings go directly to improving our operating margin, which has a direct effect on driving returns at the corporate level.
I will now turn the call over to Sherri.
Sherri A. Brillon - Encana Corp.
Good morning and thanks, Mike. We are pleased with our financial performance this quarter.
As Doug mentioned, our cash flow in the quarter was $252 million, which is a 38% increase from Q2. We continue to make tremendous progress reducing cash costs across the entire business.
At our Investor Day, we lowered our 2016 guidance for operating transportation and processing expenses, and as Mike mentioned, we are now further lowering guidance for operating expense. Our operating teams continue to execute on the initiatives identified by our operating expense task force.
In the last quarter we renegotiated our REX transportation contract. We are seeing the direct impact of this with our T&P cost down in Q3.
This relentless focus on bringing costs down contributed to higher cash flow in Q3 versus Q2. Our administrative expense this quarter includes some one-time items and non-cash LTIs.
We expect to maintain our G&A rate of $40 million to $45 million per quarter. During the quarter, we used proceeds from the sale of our DJ Basin and Gordondale assets, as well as our public offerings to repay our credit facilities in full.
As a result, our interest expense on debt in the quarter was $72 million, which is $4 million lower than Q2. With respect to capital, we continue to be committed to a focused and efficient program.
Each dollar spent is being allocated to generate quality returns. 98% of our capital this quarter was directed to our core four assets.
As Mike demonstrated, we are seeing strong production performance. We now expect that our core four Q4 2015 to Q4 2016 decline rate will be 4%.
This is less than half of our original expectation. Our hedging program provides increased confidence in our cash flow.
The details are in our corporate presentation on our website. Since the update we provided at our Investor Day, we have executed an additional 310 million cubic feet per day of NYMEX natural gas hedges for the last two months of 2016 at fixed prices averaging $3.37 per million BTUs.
We've also added hedges on approximately 20,000 barrels per day of 2017 oil and condensate volumes, half at a fixed price of $54.21, and half on three-way collar at $40, $50.31 and $60. We've taken decisive steps to solidify our balance sheet and ensure that we are well-positioned to continue executing our strategy.
We've cut our net debt in half since the year-end of 2014, reducing total long-term debt by $3.1 billion during that time. We continue to have access to significant liquidity.
We currently have more than $750 million in cash and have nothing drawn on our $4.5 billion credit facility. This gives us access to over $5 billion of liquidity.
Strengthening our balance sheet will continue to be a focus going forward. We believe financial flexibility is essential for maintaining a sustainable business throughout market cycles.
Overall, our third quarter results demonstrate strong operational and financial performance. We are pleased with our strong cash flow per share growth.
Our performance this quarter is already more efficient than the benchmark we used to build our five-year plan. I will now turn the call over to Doug.
Douglas James Suttles - Encana Corp.
Thanks, Sherri. Our third quarter results reinforce Encana as a leading North American resource play company.
We have tremendous depth in our premium return inventory with a portfolio of assets in the right places. Our approach to innovation is significantly increasing our well performance.
We've had some pretty incredible results this quarter. At the same time, we continue to meaningfully reduce our D&C cost.
We've also reached some impressive cash cost milestones. All told, our cash cost savings are over $600 million compared with just one year ago.
These results demonstrate we are one of, if not the highest performing and lowest cost operators in each of our core four assets. Our multi-basin portfolio and market fundamentals work enables us to continue to manage market and portfolio risk.
We are positioned to deliver sector-leading growth in returns. We have worked hard to build a business that is not dependent on price recovery to succeed.
We are expanding margins as we continue to shift our portfolio commodity mix to a greater balance between oil and condensate and natural gas. We are set to double our corporate margin over the next five years at flat prices.
And we have the financial capacity to exploit the inventory and capitalize on our operational excellence. Thanks for listening in on the call, and now we'd be happy to take your questions.
Operator
Thank you. We'll now begin the question-and-answer session and go to the first caller.
The first question is from Jeoffrey Lambujon from Tudor, Pickering, Holt. Please go ahead.
Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.
Good morning. Thanks for taking my questions.
In the Permian, definitely encouraging commentary on the brown sand showing no performance degradation versus the white sand. Just wondering if that's uniform across all zones or if you expect some variability as you test different zones across your acreage?
Douglas James Suttles - Encana Corp.
Yeah. Thanks for the question.
Mike'll probably have a few comments, but we've actually tested brown or domestic sand in a number of plays now and the early well performance hasn't shown any difference in any of our wells or zones. But, Mike, anything to add there?
Michael G. McAllister - Encana Corp.
No, that's right, Doug. We've tested across all our plays and we're not seeing really any degradation at all with respect to well performance as a result of sand.
And the real upside is the cost savings. As an example, in the Duvernay on a per-well basis we're saving over $130,000 per well as a result of using that sand.
So really, really encouraged by the results.
Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.
Great. That's helpful.
And then one follow-up separately on the Montney. Just looking at the mix shift pro forma for the Gordondale sale, just looking at that shift quarter-over-quarter, can you give us some context around that?
Just trying to get a sense for if that's more one-off in nature for Q3 or something we should watch for going forward.
Douglas James Suttles - Encana Corp.
Yeah. And maybe what I'd do is get Brendan and his team to follow up with you on the details on that.
But what we really did was, with the Gordondale sale, we actually sold an asset that produced a lot of NGLs and, of course, what we've been growing is in the Pipestone area which is predominantly condensate. And what we should see is that trend continue because our liquids growth in the Montney is just dominated by these higher condensate-gas ratio wells.
I think Mike mentioned the 85 barrels a million, which is what we're drilling today.
Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.
Great. Thanks for the detail.
Operator
Thank you. We do have a question from Mike Dunn from GMP FirstEnergy.
Please go ahead.
Michael P. Dunn - GMP FirstEnergy
Thanks. Good morning, everyone.
My question is on your lateral lengths, whether or not you've been pushing them higher in the Permian and Eagle Ford? And if so, just give us a sense of what range of lateral lengths you're drilling lately?
Thanks.
Douglas James Suttles - Encana Corp.
Yeah, Mike, it varies. We're always trying to push out towards longer lengths but probably staying within 10,000 feet.
Beyond there, we're not convinced that you can get the right kind of well performance and completion performance. So it's a mix, but just to give you maybe some sense, I think one of the wells we drilled in the Eagle Ford this quarter was over 9,000-foot lateral, but they tend to be shorter because of the nature of our land position.
We've drilled a couple of 10,000s in the Permian as well, but – and our average well length in the Permian is a little higher than our type curve today. Probably one other thing to mention; for instance in the Permian, we are expecting, as we go to 2017, to be doing larger pads as a general rule.
You may have caught that Mike talked about the Davidson pad. That's our 14-well pad.
But next year we're going to have a number of pads in that similar scale as we drive efficiencies.
Michael P. Dunn - GMP FirstEnergy
Great. That's all for me, Doug.
Thanks.
Douglas James Suttles - Encana Corp.
Thanks, Mike.
Operator
Thank you. The next question is from Josh Silverstein from Deutsche Bank.
Please go ahead.
Josh I. Silverstein - Deutsche Bank Securities, Inc.
Hey. Thanks.
Good morning, guys. I know there were a couple moving parts this quarter as far as some of the Gordondale volumes coming off and then the Davidson pad having some downtime.
Just trying to get a better understanding as to where the fourth quarter core four volumes are trending towards. I think as you mentioned, the increasing CapEx should help the Permian volumes, but I wasn't sure if there were any declines.
Just trying to get a better sense as to the base expectations for 4Q, just to set up the kind of 15% to 20% growth numbers you guys talked about as far as an exit rate next year.
Douglas James Suttles - Encana Corp.
Yes, Josh. I mean, a couple things to think about actually.
The capital spending in the third quarter was the lowest quarter of the year. As I mentioned, we've ramped up; we're almost at the 2017 activity levels now.
By the end of this month, I think we'll be just one rig short of where we expect to be. And most of that incremental ramp is going to come in to the Montney next year as we ramp to fill the two new gas plants coming on at the end of the year.
I think the best way to think about the fourth quarter is just use the guidance we've given on the core four for a 4% decline from the fourth quarter of last year. And I think the liquids mix should be on trend with what we've been seeing.
Josh I. Silverstein - Deutsche Bank Securities, Inc.
That's helpful. And then I know there's been a lot of activity recently over in Howard County and the Montney.
Obviously, you guys have a big position there. Will you guys start to put some rigs over there?
Any thoughts about activity for 2017?
Douglas James Suttles - Encana Corp.
Yes, we're going to have activity across the land base in the Permian next year. And really, this is all about efficient development of our inventory.
We also will actually test a few new zones next year. We, at this point, expect to actually do some drilling in both the Clearfork and the Jo Mill in 2017.
This is a minor amount as we continue to prove it up. But really, what we're trying to do is optimize capital efficiency, get the most production for the least cost, which is driving us towards bigger pads.
But it does have activity across basically what we consider the four or five. We roll Upton into Midland.
We consider that core as well but we tend to refer to it and talk to it as Midland.
Josh I. Silverstein - Deutsche Bank Securities, Inc.
Great. Thank you.
Operator
Thank you. And at this time, we have completed the question-and-answer session.
I'll turn the call back over to Mr. McCracken.
Brendan McCracken - Encana Corp.
Thank you, operator. This now ends our call.
Thank you for joining us today.
Operator
Thank you. The conference has now ended.
Please disconnect your line at this time, and thank you for your participation.