Enerplus Corporation (ERF) Q3 2018 Earnings Conference Call Transcript
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Palo Alto Networks, Inc. (NYSE: ERF)
Q3 2018 Earnings Conference Call
Nov. 9, 2018, 11:00 a.m. ET
Contents:
Prepared Remarks
Questions and Answers
Call Participants
Prepared Remarks:
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. If at any time during this call you require immediate assistance, please press *0 for the operator. This call is being recorded on Friday, November 9th, 2018. I would now like to turn the call over to Mr. Drew Mair, Manager, Investor Relations. Please go ahead.
Drew Mair -- Manager of Investor Relations
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.
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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 in Marketing. Following our discussion, we will open up the call for questions.
With that, I'll turn the call over to Ian.
Ian C. Dundas -- President and Chief Executive Officer
Thanks, Drew. Good morning, everyone, and thanks for joining us today. I'll dive right into our third quarter results. Quarterly production was up four percent 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 eight percent 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 90,500 to 93,000 BOE per day with liquids production 49,500 to 50,000 per day. Importantly, our capital budget remains on track and unchanged at $585 million. We have visibility to meaningful free cash flow in the fourth quarter and expect 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 good performance and capital efficiencies across our plays, 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 hundred dollars 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 the line of sight to competitive development economics. Given our modest entry cost in the play, we see strong value creation potential here.
With that, I will now pass the call to Jodi to talk through some of the financial and marketing highlights.
Jodine J. Labrie -- Senior Vice President and Chief Financial Officer
Great, thanks, Ian. We generated adjusted fund flow of $210 million in the third quarter compared to $193 million in capex. As Ian mentioned previously, we expect strong free cash flow generation in the fourth quarter given the later 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 realized 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 about double the norm for this time of year. We also believe that as the refineries start 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$6.00 per barrel below WTI. Our fixed physical differential sales on approximately 20,000 barrels 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 the slight 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 forecasts 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.
While this growth will add to the tightness, directionally, we think our 2019 realized Bakken differential will be approximately US$1.00 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$3.00 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$3.00 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$4.00 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 will now turn the call over to Ray.
Ray Daniels -- Senior Vice President of Operations
Thanks, Jodi. Now, to quote or volumes, we're up seven percent quarter over quarter and almost 60% year-on-year. This significant growth has been driven by consistently strong well performance across our concentrated position 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 offer 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 not a uniform solution, we plan to continue to utilize ESPs where appropriate.
Briefly, on gas 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 down days when the well was shut in for facilities modifications. The subsequent four wells, the Codell and one Niobrara brought online in July, are all meeting or tracking about 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 upside given the additional Niobrara benches of significant oil saturation.
We plan to continue delineation in 2019 along with advancing midstream plans. We will provide more granularity around the capital plans for the DJ with our 2019 budget.
With that, I'll pass the call back to Ian.
Ian C. Dundas -- President and Chief Executive Officer
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.
I will now turn the call to the operator and we're open for any questions you may have.
Questions and Answers:
Operator
Thank you. Ladies and gentlemen, should you have a question, please press star followed by one on your touchtone phone. If you're using a speakerphone, please lift your handset before pressing any key. One moment, please, for your first question.
Your first question is from Dennis Fong from Canaccord Genuity. Dennis, please go ahead.
Dennis Fong -- Canaccord Genuity -- Analyst
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 breath of free cash flow at that point in time, that you're interested in continuing pursuing that 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 a valuation metric in mind, and given your free cash flow profile as well as your current leverage metric, how should we be thinking about this going forward?
Ian C. Dundas -- President and Chief Executive Officer
Good morning, Dennis. Yeah, when we look at the opportunity now, we really see buying our shares as a highly competitive, compelling capital allocation choice that's pretty easy to think about in the context of free cash flow. As we've said for a 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 toward the end of the year, but it's a tool we will continue to keep in our toolkit and we'll give people a little more context then.
Dennis Fong -- Canaccord Genuity -- Analyst
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 just narrowing from where they happen to be, call it, 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, you're not interested in pursuing any more in terms of, we'll call it, curing the differential, the 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 on your three-way collars?
Jodine J. Labrie -- Senior Vice President and Chief Financial Officer
Sure. Hi, Dan, this is Jodi. We do feel that the current market in the Bakken is overdone with the over a 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 gonna see that differential tighten in. As I mentioned, we have 16,000 barrels a day currently now, most recently added to that, actually, at attractive levels, WTI minus $3.00 net back in the Bakken. 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 look to add to that going forward.
I guess one of your other questions was about our three-ways. We're actually feeling quite comfortable with our hedge position. We do have upside, we have protected the downside, and we participate in 2019 up to about $65.00 WTI, so we're comfortable with where we're at with that portion of our hedging program.
Dennis Fong -- Canaccord Genuity -- Analyst
Okay, perfect, and then, just lastly, let me sneak one last one in. Now that Proposition 112 has been defeated and the state of your balance sheet, are you guys gonna 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? I'll leave it at that. Thank you.
Ian C. Dundas -- President and Chief Executive Officer
As we said, we gave people some color today on well results that are encouraging, they all sort of look consistent with Maple, and that the Niobrara well is particularly important given it gives us another zone to be talking about and more resource. Yeah, it's nice that 112 is done. I think that'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 comfortable we are positioned, I think, like a lot of these things, 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've got a pretty good footprint right now that's going to have potential to drive some metrics for us.
Dennis Fong -- Canaccord Genuity -- Analyst
Okay, perfect. Thank you for the time.
Ian C. Dundas -- President and Chief Executive Officer
Thanks, Dennis.
Operator
Thank you. Your next question is from Neil Dingmann from SunTrust.
Jordan Levy -- SunTrust Robinson Humphrey -- Analyst
Hi, guys, this is actually Jordan. I just wanted to ask about how you guys are thinking about completing in the Bakken and how you approach spacing between the Three Forks and the Bakken, and if any changes have been made there or if you're thinking about doing anything differently there. The results have obviously been really strong. Any color would be great. Thanks, guys.
Ian C. Dundas -- President and Chief Executive Officer
Good morning. For those who don't know, we have Bakken across the acreage position and the first bench of the Three Forks everywhere. There's some deep bench potential in places, but typically, we think about the two zones. Our base development now, the inventory that we talk about assumes spacing at six wells in the Bakken and four wells in the Three Forks. We sort of view those as a single unit on some level, so 10 wells in a DSU.
We've tested tighter. We've watched 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 facing optimization in our minds now, it's completion optimization, and as Ray talked about in his remarks, a lot of work's going on there relative to playing with the amount of proppant, playing with perf clusters, playing with type of proppant, and I would say, oh, gosh, half of our wells were testing and think about things, looking to optimize the economic equation.
Jordan Levy -- SunTrust Robinson Humphrey -- Analyst
Great, thanks so much, guys. Again, over to the DJ, I know that you guys have been happy with the results there. Just a question how you would approach Codell versus Niobrara. I know in the press release you guys discussed that you liked what you were seeing out of the Niobrara, just thinking about how you were approaching that as you continue the delineation in the play.
Ian C. Dundas -- President and Chief Executive Officer
When we got into the play, you knew the resource was there in both zones, Codell and Niobrara, Niobrara being the bigger prize in our view, that Codell was probably the lower-risk choice initially, and that's why we initially dedicated our capital to the Codell. We've now gone to Niobrara and have been really pretty pleased with what we've seen there, a little bit because of how we were thinking about risk, initially, and then obviously, for those who know, it's a pretty big prize there in terms of resource.
As we move into next year, I think it'd be fair to assume we'll be advancing both zones. We see pad development that can facilitate testing both at the same time, effectively are off the same pad, and so we'll move forward with some more drilling next year to advance our understanding of both of the zones, and I think we've transitioned past science project now to something where we see a little insight to development economics, albeit it is still early stage.
Jordan Levy -- SunTrust Robinson Humphrey -- Analyst
Great, thanks for the color guys, great results.
Operator
Thank you, your next question is from Patrick O'Rourke from AltaCorp. Please go ahead, Patrick.
Patrick O'Rourke -- AltaCorp Capital -- Analyst
Hey, good morning, guys. Just a couple quick questions here. First, you mentioned the 16,000 barrel a day of the Bakken differential that you've locked in for 2019. There's obviously a little bit of slope to that clear brook dip right now when you look out to the futures curve. Just wondering if you can give us a little bit of color. Is that 16,000, is that flat throughout the year or is there any slope, are you more heavily hedged or locked in for the first half, then the second half or maybe some color on that structure there.
Garth Doll -- Manager in Marketing
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 then 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 -- AltaCorp Capital -- Analyst
Okay, and then the second question. In terms of the Marcellus volumes, I know you're non-operated there, but in the past, there's been some, call it volume behind pipe or ability to capture as differentials improve there. Just wondering, as we head into winter here, storage is low, if we get some cold weather 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?
Garth Doll -- Manager in Marketing
No, I don't think you should think about it that was any longer. I mean there were times where there was a lot behind pipe, today we've 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've worked through ducts, we've worked through capacity, and so, yeah, I don't view that as 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 fore market and maybe more than just a year it'd be very easy to allocate capital there, to start to grow that at a higher rate. I wouldn't anticipate -- it certainly -- it wouldn't be what we would want to do, and it hasn't been practiced of our partner at all to react to really near-term changes in the market.
Patrick O'Rourke -- AltaCorp Capital -- Analyst
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 -- National Bank -- Analyst
Yeah, good morning, three questions here. The first is just around some of the marketing conversation. As you look to get the product to some of the higher netback regions, are you using rail for any of that at the moment?
Jodine J. Labrie -- Senior Vice President and Chief Financial officer
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 at either fixed depth or index pricing.
Travis Wood -- National Bank -- Analyst
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 try to decide between, or more the allocation between North Dakota and Colorado?
Ian C. Dundas -- President and Chief Executive Officer
A hypothetical budget, qualitatively, Travis, it'll be a similar principle 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, and we don't think Colorado is going to dominate our budget next year, that's just not the nature of it. There will be spend there to advance the resource, to build for the future, to bring deliverables on, you'll sort of see it more toward the end of the year than the beginning of the year. 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. On a lot of levels you could anticipate that it could look similar year on year, bend 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 at really a good place from a resiliency perspective to make, what we think, the right choices here.
Travis Wood -- National Bank -- Analyst
Okay and then from an infrastructure perspective, any issues or constraints, kind of through a 2019 period that you could anticipate whether it's -- maybe it's both processing or egress from that type of perspective in the DJ?
Ian C. Dundas -- President and Chief Executive Officer
In the DJ specifically, so for those who don't know, one of the reasons that we were able to acquire this opportunity at such attractive terms, and one, we did it in a low point in '14 and '15, but cellphone area where its an oil development and you need gas infrastructure, and gas infrastructure wasn't in place. I mean, the main truck lines, the interstates were there, but you didn't have gathering and you didn't have processing and so now that there have 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's an economic value to it as well. Those choices range from Enerplus putting its own capital into a gathering system in a plant 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 says that there is only sort of a sensible pace that you could go on the drilling side, but we'll put some perspective around all of that as we put our whole plan together.
Travis Wood -- National Bank -- Analyst
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 -- Macquarie -- Analyst
Morning guys, thanks, just looking for a bit more granularity on the DJ, either Ray or Ian, how much better was the Niobrara well producing, versus the Codell, would you say?
Ian C. Dundas -- President and Chief Executive Officer
Comparable. Yeah, it was comparable.
Brian Kristjansen -- Macquarie
Can you give us a sense of what the Niobrara inventory is at this point?
Ian C. Dundas -- President and Chief Executive Officer
I think it's premature for that. I guess the only thinking I would add is, everywhere we see the Codell in our core area we see the Niobrara and I suppose there a couple places we see the Niobrara, I 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 benches, 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's sort of what the logs would tell you.
Brian Kristjansen -- Macquarie -- Analyst
Great, and then what do you see as your target well cost and when -- do you think you'd get there by the end of 2019?
Ian C. Dundas -- President and Chief Executive Officer
Part of the well cost, if you look at best in class today, people would be talking in the five million range, I mean EOG talks tighter than that, or lower than that, but that sort of feels like best in class today, people running full development. We are not talking about a full development scenario next year. That wouldn't make any sense at all given what the infrastructure is. So, if today, we'd raise an AFE at $7 million it would be pretty easier to say -- see a $6 million kind of number kind of number in a full development scenario. Nothing changes, but we go to full development, we'd be expecting something like six million and you'd have economics that you'd be proud to talk about and the goal for sure would be to drive past there as we move forward.
Brian Kristjansen -- Macquarie -- Analyst
Great, thanks, Ian.
Operator
Thank you. Your next question is from Aaron Swanson from Tudor Pickering Holt & Co. Aaron, please go ahead.
Aaron Swanson -- Tudor Pickering Holt & Co. -- Analyst
Yeah, thanks, just a quick question for me. I'm curious, with all the changes in the Bakken completions, what is a good well cost to you for the Three Forks and the Bakken, and if they've changed at all it'd be interesting to know?
Ian C. Dundas -- President and Chief Executive Officer
I'm still thinking eight million's a good number. DNC plus infrastructure on top of that, so DNC around seven, and that gives you some latitude for a pretty big completion, probably more than 1,000 pounds per foot. I'd say as we think about this year versus next year, we're seeing some stability in prices on some levels or costs on some levels, although we do see frack -- frac's getting cheaper, and getting cheaper, drilling may be a little more expensive on a day rate. A little bit of pressure on trucking here and there. You put it all together and stability is a pretty good way to think about it right now.
Aaron Swanson -- Tudor Pickering Holt & Co. -- Analyst
Yeah, that's good and then just on the calendar side, you guys have some heavy oil production, are we looking at economics or you look at shutting that in or is that covered off by hedges, or how should we look at that?
Ian C. Dundas -- President and Chief Executive Officer
We've got a great hedge position for our heavies, and then where we're positioned on our oil, and again, this is 10,000 barrels out of the 50, 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. We have talked about shut-ins and those kinds of things, we're certainly not doing it right now and some of that's operational logistics, just based on the nature of the specific nature of our assets under flood and then under tertiary, but yeah, we're a ways off the bottom relative to the specifics of our plays and our hedges and our realizations.
Aaron Swanson -- Tudor Pickering Holt & Co. -- Analyst
Perfect, thanks.
Operator
Thank you. Ladies and Gentlemen, as a reminder, should you have a question, please press * followed by 1. Your next question is from Brian from Capital One Securities. Brian, please go ahead.
Brian Velie -- Capital One Securities -- Analyst
Good morning everyone thanks for taking my question. I've just got one and it's 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 wells 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 zero to 60 here, or maybe not quite 60, I know that's not the plan for next year Ian, but in these early days, what kind of rates of return you might be looking for.
Ian C. Dundas -- President and Chief Executive Officer
Are we talking kilometers an hour or miles? I think it's a little premature. We'll frame that out a bit as we role the program forward. 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 of that from what others are talking about. That Maple well produced 100,000 barrels of oil in its first 12 producing months. You can fit some kind of curve on that and with a $50.00 net back 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 -- Capital One Securities -- Analyst
Okay, fair enough. Thank you very much. That's all I've got.
Ian C. Dundas -- President and Chief Executive Officer
Thank you.
Operator
Thank you, your next question is from Mike Dunn from GMP FirstEnergy. Mike, please go ahead.
Michael Dunn -- GMP FirstEnergy -- Analyst
Thanks, I just had a follow-up question folks on the new DJ basin wells, were the Codell formation wells, was the completions in engineering etcetera fairly consistent with the Maple well horizontal lengths, etcetera and whether or not you're doing anything materially different with the Niobrara well. Thanks.
Ian C. Dundas -- President and Chief Executive Officer
The short answer is, there's consistency among all the wells. The longer answer though is, even though it was delineation, we used the opportunity to advance certain -- 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 moving forward. They are all bigger kind of fracks, high rate. They're all two-mile wells laterals as well. But, there is a consistency to them.
Michael Dunn -- GMP FirstEnergy -- Analyst
Thanks, Ian, that's all for me.
Ian C. Dundas -- President and Chief Executive Officer
Thanks, Mike.
Operator.
Thank you, there are no further questions at this time Please proceed.
Ian C. Dundas -- President and Chief Executive Officer
All right. Well, appreciate everyone's time. Busy morning for many of you. Appreciate your attention today, have a good weekend, cheers.
Operator
Ladies and Gentlemen, this concludes your conference call today, we thank you for participating and ask that you please disconnect your line.
Duration: 35 minutes
Call participants:
Drew Mair -- Manager of Investor Relations
Ian C. Dundas -- President and Chief Executive Officer
Jodine J. Labrie -- Senior Vice President and Chief Financial Officer
Ray Daniels -- Senior Vice President of Operations
Garth Doll -- Manager in Marketing
Dennis Fong -- Canaccord Genuity -- Analyst
Jordan Levy -- SunTrust Robinson Humphrey -- Analyst
Patrick O'Rourke -- AltaCorp Capital -- Analyst
Travis Wood -- National Bank -- Analyst
Brian Kristjansen -- Macquarie -- Analyst
Aaron Swanson -- Tudor Pickering Holt & Co. -- Analyst
Brian Velie -- Capital One Securities -- Analyst
Michael Dunn -- GMP FirstEnergy -- Analyst
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