Nov 9, 2018
Executives
Drew Mair - Manager, Investor Relations Ian Dundas - President and Chief Executive Office Jodi Jenson Labrie - Senior Vice President and Chief Financial Officer Raymond Daniels - Senior Vice President, Operations, People and Culture Garth Doll - Manager, Marketing
Analysts
Dennis Fong - Canaccord Genuity Jordan Levy - SunTrust Robinson Humphrey Inc Patrick O’Rourke - AltaCorp Capital Inc Travis Wood - National Bank Financial, Inc. Brian Kristjansen - Macquarie Capital Markets Aaron Swanson - Tudor Pickering Holt & Co.
Brian Velie - Capital One Securities Michael Dunn - GMP FirstEnergy
Operator
Good morning, ladies and gentlemen, and welcome to Enerplus Corporation Third Quarter 2018 Results Conference Call. At this time, all lines are in listen-only mode.
Following the presentation, we will conduct a question-and-answer session. [Operator Instructions] This call is being recorded on Friday, November 9, 2018.
I would now like to turn the call to Mr. Drew Mair, Manager, Investor Relations.
Please go ahead.
Drew Mair
Thank you, operator, and good morning, everyone. Thanks for joining the call.
Before we get started, please take note of the advisories located at the end of today’s news release. These advisories describe the forward-looking information, non-GAAP information, and oil and gas terms referenced today, as well as the risk factors and assumptions relevant to this discussion.
Our financials have been prepared in accordance with U.S. GAAP.
All discussion of production volumes today are on a gross company-working interest basis and all financial figures are in Canadian dollars, unless otherwise specified. I’m here this morning with Ian Dundas, our President and Chief Executive Officer; Jodi Jenson Labrie, Senior Vice President and Chief Financial Officer; Ray Daniels, Senior Vice President, Operations; Shaina Morihira, Vice President, Finance; and Garth Doll, Manager, Marketing.
Following our discussion, we will open up the call for questions. With that, I’ll turn it over to Ian.
Ian Dundas
Thanks, Drew. Good morning, everyone, and thanks for joining us today.
I’ll dive right into our third quarter results. Quarterly production was up 4% sequentially and 22% from the same period one year ago.
However, the real story is our oil growth, which is where 90% of our capital is allocated. Quarterly oil production was up percent – was up 8% sequentially and almost 40% from one year ago.
Our capital program in the fourth quarter is largely focused on drilling in North Dakota in preparation for the 2019 program and with only modest completion activity. However, we still expect to see flat to modest growth from oil production, as we close out the year.
We’ve tightened up our production guidance to the high-end of the range. We anticipate annual production of 92,500 BOE per day to 93,000 BOE per day, with liquids production 49,500 to 50,000 barrels per day.
Importantly, our capital budget remains on track and unchanged at $585 million. We have visibility to meaningful cash – free cash flow in the fourth quarter and expected to allocate a portion of this to continue repurchasing our shares.
In September and October, we repurchased $25 million in stock and we see a compelling capital allocation opportunity in continuing down this path. Operationally, we continue to demonstrate strong well performance and capital efficiencies across our place, particularly in the Bakken.
We brought 18 wells on production in the Bakken during the quarter with average peak 30-day rates of over 1,500 BOE per day per well. In our press release this morning, we provided some encouraging results from our emerging asset in the DJ Basin.
It’s worth highlighting that we acquired our position in the DJ for a few $100 per acre and therefore, have only modest capital exposed to the play. In addition, our land position in Colorado is removed from urban areas, which we believe expose us to less regulatory uncertainty.
With the positive well results we’re seeing and with the defeat of Proposition 112, we’re planning to continue delineating our position and have line of sight to competitive development economics. Given our modest entry cost in the play, we see strong value creation potential here.
And with that, I will now pass the call to Jodi to talk through some of the financial and marketing highlights.
Jodi Jenson Labrie
Great. Thanks, Ian.
We generated adjusted fund flow of $210 million in the third quarter, compared to $193 million in CapEx. And as Ian mentioned previously, we expect strong free cash flow generation in the fourth quarter, given the lighter capital spending forecast.
In terms of priorities for this free cash flow, we anticipate being active and continuing to buy back shares under our normal course issuer bid. Moving on to realize pricing.
Bakken differentials have been very topical of late. Our realized Bakken differential in the third quarter was very attractive at US$2.54 per barrel below WTI.
However, Bakken differentials began to widen in October and we have seen substantial volatility. We believe this is largely transitory and primarily a function of significant seasonal refinery maintenance, the level of which is double – is about double the norm that – for this time of year.
We also believe that as the refinery starts to come back online, we will see differentials improve from current levels currently seen in the spot market. Given where we’ve seen December Bakken production trade to date, we expect our fourth quarter Bakken differentials to come in around US$6 per barrel below WTI.
Our fixed physical differential sales on approximately 20,000 barrels per day at around US$2.50 per barrel below WTI have meaningfully reduced our exposure to the current weakness in spot prices. The wider fourth quarter Bakken differential has resulted in a slightly wider full-year differential forecast of $3.80 per barrel below WTI.
Production growth in the basin has been higher this year than we had initially forecast, and this is causing takeaway to get tighter. But the Bakken continues to be in an advantageous position in terms of pipeline optionality and rail infrastructure.
In addition, we expect to see the expansion of existing pipeline capacity and potentially new pipelines in the basin. This should all help keep Bakken differentials in a competitive range longer-term.
We also think some of the Bakken supply forecast in the market are too aggressive. Our work points to Bakken production growing by approximately 125,000 barrels per day year-over-year in 2019 to average about 1.4 million barrels per day.
So while this growth will add to the tightness, directionally, we think our 2019 realized Bakken differential will be approximately US$1 per barrel wider than what we expect to average in 2018. We have also recently added to our 2019 Bakken fixed physical sales and we now have around 16,000 barrels per day fixed, at a differential of about US$3 per barrel below WTI for 2019.
Moving on to the gas side. Our Marcellus differential in the quarter was US$0.48 per Mcf below NYMEX, and we expect to see this tighten further in the fourth quarter, as the Atlantic Sunrise pipeline began flowing in early October.
The spot market in the Marcellus is very strong today, due largely to low-storage balances in the region heading into the winter. Leidy cash prices have averaged around US$3 per Mcf.
so far this month, and are now trading near US$3.65 per Mcf, with current spot prices in the Transco Z6 non-New York market trading near US$4 per Mcf. We anticipate this strength to continue through the end of the year.
As a result, we expect our realized Marcellus basis differentials for the fourth quarter will average US$0.30 per Mcf below NYMEX or better and are maintaining our 2018 Marcellus differential guidance of US$0.40 per Mcf below NYMEX for the entire year. I’ll now turn the call over to Ray.
Raymond Daniels
Thanks, Jodi. North Dakota volumes were up 7% quarter-over-quarter and almost 60% year-on-year.
The significant growth has been driven by consistently strong well performance across our concentrated at Fort Berthold. In the third quarter, we had several wells with peak consecutive 30-day production rates of over 2,000 barrels of oil equivalent per day.
We continue to focus on maximizing economics and improving capital efficiencies. And as a result, we are constantly tailoring elements of our completions design.
This past quarter, we varied proppant intensity from 600 to 1,600 pounds per foot, varied the number of clusters between five and 15 per compartment and increased the compartment length to 300 feet on a number of wells. On the production side, we’ve begun to test gas lift or ESPs on certain wells before moving to rod and pump.
ESPs have the potential to significantly increase production rates in the first 12-plus months. Results to date have been positive and the acceleration of production volumes improves well economics.
Although in our uniform solution, we plan to continue to utilize ESPs where appropriate. Briefly on gas process – processing in the Bakken, it is getting tight and we expect it to remain tight until Q2 next year.
We continue to manage through the tightness by deploying portable NGL units as needed and don’t foresee this impacting our plans in 2019. Coming to our well results in the DJ Basin, we now have five wells in the DJ and the results are encouraging.
The Maple well completed in the Codell formation has produced approximately 100,000 barrels of oil in the first 12 producing months. This number excludes stone days when the well was shut and for facilities modifications.
The subsequent four wells, three Codell and one Niobrara, brought online in July, are all meeting or tracking above the Maple well and compare favorably to recent wells across the basin. The Niobrara well was completed in the lower Niobrara B Chalk and is among the strongest of our DJ wells to date.
The Niobrara potentially adds meaningfully to the scope of this asset, and there could be further upsides given the additional Niobrara benches of significant oil saturations. We plan to continue delineation in 2019, long with advancing with stream plans.
We will provide more granularity around the capital plans for the DJ with our 2019 budget. And with that, I’ll pass the call back to Ian.
Ian Dundas
Thanks, Ray. In summary, we remain on track this year to deliver the strong results that our shareholders have come to expect.
Looking ahead to 2019, we are well-positioned to deliver another year of disciplined, returns-focused growth, while maintaining our strong financial capacity. And so I will now turn the call over to the operator and we’ll open for any questions you may have.
Operator
Thank you. [Operator Instructions] One moment please for your first question.
Your first question is from Dennis Fong from Canaccord Genuity. Dennis, please go ahead.
Dennis Fong
Hey, good morning, and congrats on a good quarter. Just two questions here.
The first is just on share repurchases. You kind of noted in Q4, obviously, given that you have a breadth of free cash flow at that point in time that you are interested in continuing pursuing that – the repurchase program.
Looking into 2019, how should we think about that? I know you’ve stated in the past that you kind of have a number and valuation metric in mind.
And given kind of your free cash flow profile, as well as your current leverage metric, like how should be thinking about this going forward?
Ian Dundas
Good morning, Dennis.
Ian Dundas
Good morning.
Ian Dundas
Yes. So, when we look at the opportunity now, we really see buying our shares as a highly competitive compelling capital allocation choice.
It’s pretty easy to think about in the context of free cash flow. As we’ve said for the long time, we think keeping our eye on share repurchase is a really important thing, as you’re thinking about delivering value to shareholders and we will continue to keep our eye on that.
I think, we’ll frame all of that as we roll out a comprehensive budget likely towards the end of the year. But it’s a tool we will continue to keep in our toolkit and give people a little more context then.
Dennis Fong
Perfect. And then the second question here is just on the differentials and so forth.
It sounds like from your prepared remarks that you feel pretty comfortable about the Bakken diff kind of narrowing from where they happen to be, call in, December as the refining capacity comes back available. Does that mean that the 16,000 barrels a day in 2019 is something that you’re comfortable with?
Are you not interested in pursuing anymore in terms of, call it, the curing the differential to WTI on that basis? How should I think about that?
And then just secondarily on the hedging program, are you guys comfortable with the just shy of 25,000 barrels a day you have in your three-way collars?
Jodi Jenson Labrie
Sure. Hi, Dennis, this is Jodi.
So we do feel that the current market in the Bakken is overdone with over a 1 million barrels a day offline right now in demand. We do believe that once we see the refiners come back on later in November and into December, we’re going to see that differential tightening in.
As I mentioned, we have 16,000 barrels a day, currently now, most recently added to that actually at attractive levels WTI minus $3 net back in the Bakken. So we would look if given the opportunity to add to that, that wouldn’t be right now just given the current spot prices.
So I believe we’d love to add to that going forward. I guess, one of the other questions was about our three ways.
We’re actually feeling quite comfortable with our hedge position. We do have upside.
We protected the downside and we participate in 2019 up to about $65 WTI. So we’re comfortable with where we’re at with that portion of our hedging program.
Dennis Fong
Okay, perfect. And then just lastly, if I can sneak in one last one.
Is the – now that kind of Proposition 112 has been defeated and kind of the state of your balance sheet. Are you guys going to be looking to, we’ll call it, increase your exposure or land position in the Niobrara?
How do you feel about your current land position? And I’ll leave it there.
Thanks.
Ian Dundas
So as we said, we gave people some color today on well results that are encouraging. They also look consistent with Maple and that the Niobrara well is particularly important, given – it gives us another zone to be talking about more resource.
Yes, it’s nice that 112 is done. I think it’s taken a lot of noise out of the system.
When we think about that play, I would expect, or I guess we plan to allocate some capital now to that play next year to continue the delineation activity. It’s early stage, but we could anticipate putting some money into infrastructure next year as well based on the results we’ve had to date.
In terms of expanding the opportunity set, how comfortably we are positioned? I think like a lot of these things, we’ve got a really – we’re in a really good position financially that we can do whatever makes sense.
And we’ll be opportunistic, we’ll look for opportunities to expand it. But we’re – we’ve got a pretty good footprint right now, that’s going to – have potential to drive some metrics for us.
Dennis Fong
Okay, perfect. Thank you for the time.
Ian Dundas
Thanks, Den.
Operator
Thank you. Your next question is from Neal Dingmann from SunTrust.
Neal, please go ahead.
Jordan Levy
Hi, guys. This is actually Jordan.
Just wanted to ask about how you guys are thinking about completing in the Bakken? And how you approach spacing, kind of between the Three Forks in the Bakken?
And if any changes have been made there or kind of, if you’re thinking about doing anything differently there the results have obviously been really strong? Any color would be great?
Thanks, guys.
Ian Dundas
Good morning. So for those who don’t know, we have Bakken across the acreage position in first bench of Three Forks everywhere.
There’s some deeper bench potential in places. But typically, it’s – if you think about the two zones, our base development now, the inventory that we talk about assumes spacing at six wells in the Bakken and in three wells – sort of four wells in the Three Forks.
We sort of view those as a single unit on some levels. So 10 wells in DSU.
We’ve tested tighter. We watch other people test tighter.
We think that’s a number that makes sense for us. We’ll continue to watch.
I guess, there’s the possibility of going tighter in the Three Forks. We don’t see a lot of evidence that says that’s the best economic choice right now.
So it’s not as much basing optimization in our minds now, it’s completion optimization. And as Ray talked about in his remarks, a lot of work is going on there relative to moving – playing within our proppant, playing with per foot clusters, playing with tighter proppant.
And I would say, oh, gosh, half of our wells were testing and things looking to optimize the economic equation.
Jordan Levy
Great so much – thanks so much, guys. And then just kind of, again, over to the DJ and because I’ve been happy with the results there.
Just kind of question, how you would approach kind of Codell versus Niobrara? I know in the press release you guys discuss that you like what you are seeing out of the Niobrara.
Just kind of thinking about how you’re approaching that as you continue the delineation in the play?
Ian Dundas
So we – when we got into the play, I mean, you knew the resource was there in both zones, Codell and Niobrara. Niobrara being the bigger price.
In our view, the Codell was probably the lower-risk choice initially. And that’s why we initially dedicated our capital to the Codell.
We’ve now got into Niobrara and have been totally pretty pleased with what we’ve seen there a little bit, because of how we were thinking about risk initially. And then obviously, it’s a – for those who know, it’s a pretty big price there in terms of resource.
So as we move into next year, I think, it’ll be fair to assume, we’ll be advancing both the zones. We see the pad development that can facilitate testing both at the same time effectively or off the same pad.
And so, we’ll move forward with some more drilling next year to advance or understanding of both of the zones. And we’re – I think we trend – we’ve transitioned past lines project now to something where we see line of sight to development economics, albeit, it is still early stage.
Jordan Levy
Great. Thanks for the color, guys.
Great results.
Operator
Thank you. Your next question is from Patrick O’Rourke from AltaCorp.
Patrick, please go ahead, Patrick.
Patrick O’Rourke
Hey, good morning, guys. Just a couple of quick questions here.
First, you mentioned the 16,000 BOE a day – barrel a day of the Bakken differential that you’ve locked in for 2019. There’s obviously a little bit of slopes to that Clearbrook diff right now when you look out to the future’s curve.
Just wondering if you can give us a little bit of color. Is that 16,000?
Is that flat throughout the year? Is there any slope?
Are you more heavily hedged or locked in for the first-half than the second-half, or maybe some color on that structure there?
Garth Doll
Hi, Patrick, it’s Garth. We have a little bit of shape to it, but it’s not significant.
We’ve got hedge volumes in place on that pretty much monthly January through the year, maybe a little bit less in parts of Q1 than we see the rest of the year. But 16 is – it’s a pretty good average for the entire year, that’s the right way to think of it.
Patrick O’Rourke
Okay. And then second question.
In terms of the Marcellus volumes, I know you’re non-operated there. But in the past, there has been some, I’ll call it, volume behind pipe or ability to capture as differentials improve there.
Just wondering as we head in the winter here, storage is low. If we get some cold whether and we see some really strong Northeast gas pricing.
Do you have the ability or in combination with Chief to increase some of the volumes there and capture that?
Ian Dundas
No, I don’t think you should think about it that way any longer. I mean, there were times where there was a lot behind pipe.
Today, we run through a fair amount of that. If you think about the profile capital in the last year or so, it’s been pretty modest, and we work through docs we work through capacity.
And so, yes, I don’t view that, it’s being something that would ramp up dramatically based on a near-term spike. I do think longer-term, if you start to see some real strength in the forward market and maybe more than just a year, it would be very easy to allocate capital there to start to grow that at a higher rate.
I don’t – I wouldn’t anticipate it certainly will – it wouldn’t be what we would want to do and it hasn’t been the practice of our partner at all to react to really near-term changes in the market.
Patrick O’Rourke
Okay. Thanks a lot, guys.
Operator
Thank you. Your next question is from Travis Wood from National Bank Financial.
Travis, please go ahead.
Travis Wood
Yes. Good morning.
Three questions here. The first just round some of the marketing conversation.
As you look to get the product to some of the higher net back regions. Are using rail for any of that at the moment?
Jodi Jenson Labrie
No. We don’t move any of our own crude on rail in our name, but we would consider selling to buyers who have rail capacity.
About 70% of our production is sold into the dapple system and either fixed depths or index pricing.
Travis Wood
Okay, thank you. And then from a theoretical 2019 capital budget.
What – and especially considering DJ success here. What types of outputs or other more maybe qualitative items are you guys considering right now as you contemplate that capital program and and try to decide between or more the allocation between North Dakota and Colorado?
Ian Dundas
The hypothetical budget. Qualitatively, Travis, it will be similar principles that we’ve applied for quite a few years.
I guess, balance sheet strength is now one that gives us a lot of flexibility. As we think about transitioning into a little more Colorado spend, I mean, don’t think Colorado is going to dominate our budget next year.
That’s just not the nature of it. So there will be spend there to advance the resource, to build for the future, to bring deliverables on, sort of – you’ll start to see it more towards the end of the year than the beginning of the year, where we’re always focused on having an operational plan that makes a lot of sense.
We’re interested in managing our growth and managing economics. So on a lot of levers you could anticipate, but it could look similar to year-on-year.
Travis Wood
Yes.
Ian Dundas
And a bit more allocate some to Colorado to continue to grow. We’ll put a fine point on all of that stuff, specifically as we move through the end of the year and see where oil stabilizes and all those sorts of things.
But as Jodi highlighted, we’re really in a good place from a resiliency perspective to make – we think the right choices here.
Travis Wood
Okay. And then from an infrastructure perspective, any issues or constraints kind of through the 2019 period that, that you could anticipate, whether it’s – maybe it’s processing or egress from that type of perspective in the DJ?
Ian Dundas
At the – in the DJ, specifically. So for those who don’t know, I mean, one of the reasons we were able to acquire this opportunity at such attractive terms and one we did it in a low point in 2014 and 2015.
But it’s also an area where it’s an oil development and you need gas infrastructure and gas infrastructure was in place. I mean, the main trunk lines interstate through there, but you didn’t have gathering and you didn’t have processing.
And so now that there has been some interesting well results in the area. There are a series of choices available to producers in terms of dealing with the gas and, I’d say, dealing with the gas, it’s actually something, where there is an economic value to it as well.
Those choices range from Enerplus putting its own capital into a gathering system in a plan to a portion of that. There are some third-party choices available.
So, those things have to be advanced and that will impact the timing of the spend next year. And so there is a only a sort of a sensible pace that you could go on the drilling side.
But we’ll put a perspective around all of that as we put our whole plan together.
Travis Wood
Okay. That’s very helpful.
Thanks, guys.
Operator
Thank you. Your next question is from Brian Kristjansen from Macquarie.
Brian, please go ahead.
Brian Kristjansen
Good morning, guys. Thanks.
Just looking for a bit more granularity on the DJ either Ray or Ian, much better was the Niobrara well producing versus the Codell, say?
Ian Dundas
Comparable
Brian Kristjansen
Yes. And then…
Ian Dundas
It was comparable.
Brian Kristjansen
Can you give us a sense of what the Niobrara inventory is at this point?
Ian Dundas
I think, it’s premature for that. I guess, the only thing I would add is, everywhere we see the Codell sort of in our sort of core area we see the Niobrara.
And I suppose there’s a couple of places we see the Niobrara think it might be a little more perspective than the Codell. For the geologists on the call, there is a far thicker package in the Niobrara.
And so you have, I guess, the potential for multiple bench. But it sets up the potential for sort of a double of where we were on the Codell, and we’ll see as we get more information, but that sort of the what the logs we tell you.
Brian Kristjansen
Great. And then what do you see as your run – like your target well costs?
And when do you think you could get there by the end of 2019?
Ian Dundas
Total well costs, if you look at best-in-class today, people would be talking in the $5 million range. I mean, the EOG talks tighter than that or lower than that.
But that sort of feels like best-in-class, say, people running a full development. We’re not talking about a full development scenario next year, that wouldn’t make any sense at all, given where the infrastructure is.
So, if today, we’d raise an AFE, it’s $7 million, you would be pretty easy to say – see $6 million kind of number in a full development scenario. So nothing changes, but we go to full development.
We’d be expecting something like $6 million and you have economics that you would be proud to talk about, and the goal for sure would be to drive past there as we move forward.
Brian Kristjansen
Great. Thanks, Ian.
Operator
Thank you. Your next question is from Aaron Swanson from Tudor Pickering Holt & Co.
Aaron. please go ahead.
Aaron Swanson
Yes, thanks. Just a quick question from me.
Curious with all the changes in the Bakken completions. What is the well cost to you at Three Forks and the Bakken, and and if it changes all the interesting to know?
Ian Dundas
Still thinking $8 million is a good number, DNC plus infrastructure on top of that. So DNC around $7 million, and that gives you some latitude for a pretty big completion, probably more than a 1,000 pounds per foot.
I’d say, as we think about it last, I guess. this year this versus next year, we’re seeing some stability in prices on some levels or costs on some levels.
Although, we do see fracs getting cheaper than getting cheaper drilling maybe a little more expensive on a day rate, a little bit of pressure on trucking here and there. So you put it all together and stability is a pretty good way to think about it right now.
Aaron Swanson
Yes it’s good. And then just on the calendar side, you guys have some heavy oil production.
Are you looking at economics? Are you looking at shutting that in, or is that covered off by hedges or how should we look at that?
Ian Dundas
We’ve got a great hedge position. We’re rushing – so we’ve got a great hedge position in Canada for heavy use.
And then our – where we’re positioned on our oil. And again, this is 10,000 barrels out of the 50,000, so it’s relatively modest.
But where we’re positioned, we’re generally getting better pricing as well. So, we wouldn’t have some of the acute issues that other producers would be facing.
And we have talked about shut ins and those kind of things. We’re certainly not doing it right now.
And some of that operational logistics is based on the nature of the – nature of our asset under flood and under tertiary. But – yes, we’re always off the bottom relative to the specifics of our place in our hedges and our realization.
Aaron Swanson
Perfect, thanks.
Operator
Thank you. [Operator Instructions] Your next question is from Brian from Capital One Securities.
Brian, please go ahead.
Brian Velie
Good morning, everyone. Thanks for taking my question.
I’ve just got one and kind of an add on to the DJ commentary. Thanks for the color on the well cost there, and what to think about looking forward.
I wondered if – now that you’ve got a few more miles under your belt, if you were willing to provide maybe some guideposts for what you were thinking about in terms of IRRS that those wells might provide as we kind of go from 0 to 60 here, or maybe not quite 60, I know that’s not the plan for next, Ian. But in these early days, what kind of rate to return you might be looking for?
Ian Dundas
Kilometers an hour or miles per hour? Yes, we
Brian Velie
I know.
Ian Dundas
I think it’s a little premature.
Brian Velie
Okay.
Ian Dundas
We’ll bring that out a bit, as we roll the program forward. I’d say, if you want to take a look at our well results and you plot those well results up against core DJ drilling, we’re right in the middle of it.
And so I think you can extrapolate a fair amount that from what others are talking about. That, that Maple well will produce $100,000 barrels of oil in its first 12 producing months.
You can fit some kind of curve on that. And with a $50 netback out there, it looks pretty robust.
But we’ll frame that up a little bit more as we move through the end of the year.
Brian Velie
Okay, fair enough. Thank you very much.
Thank all we’ve got.
Ian Dundas
Thank you.
Operator
Thank you. Your next question is from Mike Dunn from GMP FirstEnergy.
Mike, please go ahead.
Michael Dunn
Thanks. So just sort of follow-up question folks on the new DJ Basin wells.
Were the Codell formation wells where they – where is the completions and engineering, et cetera, fairly consistent with the Maple well, horizontal lengths, et cetera. And whether or not, you’re doing anything materially different with the Niobrara well?
Thanks.
Ian Dundas
The short answer is, there is consistency amongst all the wells. The longer answer, though, is even there was delineation, we use the opportunity to advance understanding of certain variables.
So, we don’t move seven things around from one completion to the next at this stage of development. But we are learning things as we move forward.
They are all bigger kind of fracs, high-rate. There are too many wells – laterals as well, but there is a consistency to them.
Michael Dunn
Thanks, Ian. That’s all for me.
Ian Dundas
Thanks, Mike.
Operator
Thank you. There are no further questions at this time.
Please proceed.
Ian Dundas
All right. We’ll appreciate everyone’s time in this busy morning for many of you.
I appreciate your attention today. Have a good weekend.
Operator
Ladies and gentlemen, this concludes your conference call today. We thank you for participating, and ask that you please disconnect your lines.