Extraction Oil & Gas' (XOG) CEO Mark Erickson on Q4 2017 Results - Earnings Call Transcript

Extraction Oil & Gas, Inc. (XOG) Q4 2017 Earnings Conference Call February 28, 2018 10:00 AM ET

Executives

Louis Baltimore - Director of Investor Relations

Mark Erickson - Chairman and Chief Executive Officer

Matthew Owens - President

Russell Kelley - Chief Financial Officer

Tom Brock - Chief Accounting Officer

Eric Jacobsen - Senior Vice President, Operations

Analysts

Welles Fitzpatrick - SunTrust

Paul Grigel - Macquarie

David Deckelbaum - KeyBanc

Jeoffrey Lambujon - Tudor, Pickering, Holt & Co

Irene Haas - Imperial Capital

Brad Heffern - RBC Capital Markets

Marshall Carver - Heikkinen

Jeffrey Campbell - Tuohy Brothers

Jeanine Wai - Citigroup

Operator

Good morning. I am Chelsea, and I will be your conference facilitator today. I would like to welcome everyone to the Extraction Oil & Gas Fourth Quarter 2017 Financial and Operating Results Conference Call. All lines have been placed on mute to prevent any background noise [Operator Instructions].

Please be advised that the remarks today, including answers to your questions, include statements that Company believes to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently anticipated. Those risks include, among others, matters that the Company described in its financial and operating results, news release issued yesterday and in its filings with the Securities and Exchange Commission.

Extraction disclaims any obligation to update these forward-looking statements. While the Company believes these forward-looking statements are reasonable, they are subject to factors, such as commodity prices, competition, technology, and environmental and regulatory compliance. The Company's drilling schedules, capital plans and other factors may cause its results to differ materially.

I would now like to turn the call over to Louis Baltimore, Extraction's Director of Investor Relations.

Louis Baltimore

Thank you, and good morning to everyone. We're glad you could join us today for our fourth quarter earnings call. With us today on the call, we have Mark Erickson, our Chairman and CEO; Matt Owens, the Company's President; Rusty Kelley, our CFO; Tom Brock, our Chief Accounting Officer; and Eric Jacobsen, our SVP of Operations.

I'd like to remind you that today's call, in addition to the aforementioned forward-looking statements, also includes a discussion of certain non-GAAP financial measures. Please be sure to read our full disclosure on forward-looking statements and GAAP reconciliations in our earnings release and in our filing on Form 10-K, which we provided yesterday evening after the close of trading.

I'll now turn over the call to Mark Erickson, to go through some of the highlights for this quarter.

Mark Erickson

Thanks, Louis. Good morning to everyone. 2017 was a transformational year for us at Extraction. We exited the year with 20 years of high quality drilling inventory. Total proved reserves increased 23% to $293 million equivalent barrels. We grew our total equivalent production by 73% year-over-year, while our crude oil production grew over 80%. For the fourth quarter, we doubled our total equivalent production compared to the first quarter of 2017. While our crude oil production increased by 2.5 times.

Our crude oil for both the full year and the fourth quarter came in near the high end of our guidance ranges while out total equivalent production came in above the midpoint. We did this while coming in right at the low end of our D and C budget for the year.

Turning to this year. We remained focused on maintaining our low operating cost and CapEx structures. We have the benefit of several tailwinds when it comes to capital efficiency. Our development is focused on our southern acreage during the first half of this year where our wells do not have to battle high line pressures and therefore produced better. With the addition of DCPs plant 10 in the third quarter, our base production should improve. We will have another 25 wells in Greeley ready to turn on and another 20 Greeley wells later in the year. As you can see on page 10, in our investor presentation, our drilling wells are producers and range as some of our best inventory.

With that, I'm going to turn the call over to Rusty to go through financial highlights. Additionally, Matt will be covering our operating results in more detail, including the very encouraging well results we continue to see, especially those wells that are producing unconstrained into the Western Gas system.

Russell Kelley

Thanks Mark. I'd like to quickly touch on some financial highlights from the reporting period. Our liquidity and balance sheet remains strong. We exited the fourth quarter with $435 million undrawn on our borrowing base. During January, we issued $750 million of senior unsecured notes due in 2026 for the 5 and 5As coupons and increased our borrowing base to $700 million. Pro forma for this increased borrowing base after giving effects to letters of credit, we ended the fourth quarter with over $740 million of available liquidity.

We continue to target a long-term run rate of 1.5 times net debt to EBITDAX. On a run rate basis based on our six months trailing EBITDAX annualized, we were just above 2 times. Our EBITDAX continues to grow along with our production outpacing any incremental borrowings. We continue on track for our goal of all in cash flow neutrality in the second half of this year using $50 WTI price deck. As we approach this point, we expect our production and EBITDAX to continue to grow without any incremental borrowings, putting us on a clear path to get back to that 1.5 range in a quick fashion.

Now I'll turn it over to our President, Matt Owens, to cover our operational highlights.

Matthew Owens

Thanks, Rusty. I want to touch on the encouraging results we continue to see in our development program, while providing you with some more context on the impacts of higher line pressures in our Northern quarter acreage position. As we’ve said previously, about 75% of our acreage in the quarter produces into unconstrained third party systems, which we are targeting with our first half development.

If you turn to page nine in our investor presentation, you'll see that we show our Niobrara wells and our Southern acreage turned in line during the fourth quarter in the Western Gas System compared to the enhanced completion wells in our Windsor area that are currently constrained. Despite these high line pressures, the wells in our Windsor development program utilizing enhanced completions, have continue to produce with strength but not nearly as strong as they would if they were no line pressure constraints. While we think the rock is very similar in our southern acreage, the improvement in well performance as a result of lower line pressures is very evident on the chart.

If you turn to page 10, you'll see the performance of our Triple Creek pad compared to our type curves and the impact highline pressures are having on this pad. This was a 22 well pad of 2.5 mile wells in Greeley that we turned on line at the end of 2017. Most of these wells are heavily constrained by line pressures but we have two Niobrara wells that we are able to flow largely unconstrained to get an idea of how these wells will perform in a more manual environment.

As you can see in this chart, they are very strong performers, nicely above our 50% enhanced type curve. Keep in mind, in Greeley, we use standard completions, which costs less than the enhanced frac design we utilized on most Niobrara wells during 2017. The constrained production from those other 20 Triple Creek wells isn’t gone, it's just are waiting to start-up of the next plan to alleviate the line pressure issue.

There are two main takeaways from this data. First the wells we've been turning on lately are fantastic performers. They are significantly better than the wells we were turning on during the first three quarters in 2017; whether it's our southern DJ Basin acreage on the Western Gas System where the Triple Creek wells, if we strip out the impact of high line pressures, these wells are producing well in excess of our type curves; second our Greeley acreage is something really special as it is producing in excess of our 50% enhanced type curve where we get the added capital efficiency from using our less expensive standard completion design to get similar levels of production.

This concludes management’s prepared remarks. Thank you for participating on our call today. Operator, I would now like to turn the call over to the Q&A session.

Question-and-Answer Session

Operator

Thank you [Operator Instructions]. Thank you and our first question comes from the line of Welles Fitzpatrick with SunTrust. Your line is open.

Welles Fitzpatrick

Can you talk about, I mean jumping to the second Hawkeye well. Can you talk about how you guys completed that differently than the first? And if you had any change in the way you were flowing it back?

Mark Erickson

First of all, the second well in Hawkeye was a longer lateral than the first one. As far as the completion design wins, we try to keep the profit loading relatively the same to what the first well was. But we did end up pumping a little bit more water, more fluid heavy design on the second well than we did the original well.

Welles Fitzpatrick

And so presumably with the longer lateral just like we like we see in the core of the basin, you would expect those to maybe come on a shade lower on a per foot basis, but that holding stronger?

Mark Erickson

Yes, that’s typically what we see in the areas further north, like in Windsor, the shorter the lateral usually the higher the per 1,000 foot IPs are in the first 30, 60, 90 days. But the difference with the longer laterals is they typically have a shallower effective decline and that’s something that will come out after six to nine months of production.

Welles Fitzpatrick

And then one last one, the $70 million of divestitures. I don’t suppose there’s any acreage numbers that you guys would be willing to share with us today on that?

Russell Kelley

We can’t give the details of those until they close. But we can assure you it’s very much in line with what we’ve signaled to the market. This is going to be non-strategic assets, very far back in the drilling inventory. And as we mentioned in our press release, would have no impact on guidance. This is stuff that we’re very pleased with the outcome.

Operator

Thank you. And our next question comes from the line of Paul Grigel with Macquarie. Your line is open.

Paul Grigel

I guess first is on line pressures for a second. Could you guys discuss through the 2018 budgeting and guidance process, how you worked in. Your assumptions around the impacts of line pressures you are determining and your confidence into where those are performing relative to your expectations at this point in time?

Mark Erickson

So for the phase production of the PDP that we turned on mostly in 2017, that is going into the constrained midstream systems. We have budgeted and forecasted that, as though it would be constrained. So the newer wells that we’ve been turning on, mostly at the end of the fourth quarter and then everything in the first quarter and virtually everything in the second quarter, will be going into the western system, which will not have any line pressure constraint. Page nine is a good example showing the difference between those wells in each area.

Paul Grigel

And I guess changing tones to the cash flow. You made the comment that the cash flow neutrality could be pulled forward if occurred prices stay higher and the focus on that. And Rusty you mentioned in the prepared remarks focusing on getting that down. Is that the first priority, and what goal should we be thinking of there? And just the order of priorities for any excess cash flow that does come, be it asset sale proceeds or higher commodity prices?

Russell Kelley

I would say that we're in the enviable position that what's current commodity price levels, that we expect to have start bringing up cash flow in the back half of 2018 and with considerable free cash flow going forward. At this cycle of our company, we’ve had a lot of discussions about this. And I think when you look at our management incentives, we’re very much incentivized to be very shareholders friendly and that includes returning capital to investors. When we look at it at this stage of our company, number one priority is strengthen the balance sheet. And after we get that done we think at this stage of our company that share repurchases would be the best path to follow.

Paul Grigel

And is there an explicit leverage goal or an area where you guys at least aim to get to first before opening or broadening, is that also within that incentive plan as well?

Russell Kelley

We’ve signaled to the market that we're targeting 1.5 net debt ratio by the end of the year. That’s also one of our management incentives. Although, the board has actually made it much tighter than that and we don’t disagree with the Board.

Operator

Thank you. And our next question comes from the line of David Deckelbaum with KeyBanc. Your line is open.

David Deckelbaum

Matt, I think in your prepared remarks and the slide deck, you guys highlighted the performance for unconstrained wells. I guess, one in the Triple Creek area and Greeley, and the others going into Western Gas. I guess, as we think about well productivity in your program, is it fair to say that -- are you looking at the Greeley areas as your most productive. So that when the DCP system is more -- it's freed up a bit more that that’s when you would enter a more capita efficient. I know that you have plenty of optionality on to Western. But do you look at the unconstrained Greeley as being your most prolific area?

Matthew Owens

Yes, Greeley is our most prolific area, mostly because it is right in the center of the basin and it is completely virgin, there is no vertical well. So it’s an untrained reservoir in there. And if you look at slide 10, you can see the wells that were flowing on a more normal size choke for the two and half mile lateral, the wells that make up the blue line. And those wells over 60 days straight have been anywhere between 1,600 and 2,000 boe a day over 50% oil. Even the wells that are constrained on that pad are still flowing 1,200 boe a day or greater with the similar percentage of oil. So that is where we think the biggest bump in our production will come when the line pressures are released sometime in the third quarter, we’ll be able to open most -- we'll be able to open all the rest of the wells that make up that green line onto the size chokes that well that make up the blue line are on.

David Deckelbaum

And that’s going to comprise the majority of your rig program over the next few years?

Matthew Owens

So we have this pad that came online virtually the tail end of the fourth quarter, but we do have another 17 well pad a 2.5 mile laterals in Greeley that we’re currently -- that have been drilled and we’re currently targeting to bring those online right at the same time the new plant is coming on. So there will be a significant amount of production coming from this area in 2018.

David Deckelbaum

Rusty, just a last question from me is just you guys completed $70 million of divestiture so far. I guess, as you look at ’18, do you have an explicit target in mind or should we loosely think about you just offsetting your non D&C budget with non-core sales?

Russell Kelley

So we do have some targets in mind. We have not disclosed that to the market, partly because we want to be careful with setting expectations. What I’ll tell you though is the way we get to those targets is a lot of what Mark was talking about with regards to target levels on the balance sheet relative to where we are in the commodity price in 2018. So you can expect us to continue moving forward with this program, and we’ll continue to give updates on a quarterly basis.

Mark Erickson

We really view our non-strategic asset sales as offsetting lease purchases, which are targeting stuff near the drill bit. It’s really portfolio optimization. We’ve got a very robust inventory of acreage and drilling locations, and now it’s about increasing working interest and buying stuff in our really high quality high profile areas and taking stuff and monetizing stuff from the back end of our inventory, which is still very economic. But just it’s in the back end of our inventory.

Operator

Thank you. And our next question comes from the line of Jeoffrey Lambujon with Tudor, Pickering, Holt and Company. Your line is open.

Jeoffrey Lambujon

From a system standpoint, you mentioned Western Gas as a system that most of the wells from the CS program will flow into. So as you look through planning out to 2019 and beyond, what’s the -- 2018 what’s the infrastructure that’s in place today support, just wanted to get your thoughts on how you’re planning the midstream size as you look into the out years?

Mark Erickson

So we’re planning our development and we have been starting in the back half of 2017 around any midstream constraints that we could possibly see which is why the most of wells or all the wells returning on in the first half of this year are going into a different system. There are other players in the basis as well, private companies that are looking to build out robust midstream systems down in the southern part of the fields, especially around the Hawkeye area. So we’re in negotiations with those. But really the main constraints that we see were in the northern part of our position and really in the first half of 2018, but we think the plan that DCP has going forward with the next few plans should alleviate that.

Jeoffrey Lambujon

And then one follow up on, I guess the Hawkeye with respect to the plan you got there for this year. Can you give some more detail on just well time in the area, where the focus will be from a geographic standpoint relative to the operated wells you’ve got on so far? And if those will test anything unique versus what you’ve seen to-date in the area?

Mark Erickson

So if you look at slide 13, that’s our Hawkeye acreage map. The two wells that we drilled so far have been on the eastern side of our acreage. In 2018, we plan to drill between 14 and 20 wells in the Hawkeye area. One of those pads will be on the western side of our acreage, the northwestern part of Arapahoe County. There we’ll be testing multiple benches and spacings, that will be our spacing test in the Niobrara. The other pads that we’ll be drilling are actually on -- if you’re looking at this map north and west of the work Denver, so they’re in the northern Hawkeye area. There we’re fairly comfortable and confident with the spacing that we have but we’ll be drilling Niobrara and Codell in that area.

Operator

Thank you. And our next question comes from the line of Irene Haas with Imperial capital. Your line is open.

Irene Haas

Wondering if you can give us a little color on the northern extension acreage, what has been going on in that neighborhood and when could we see well results from you guys. And ultimately how those set rank was in your portfolio?

Mark Erickson

Yes, so as you’re all probably aware, there’s been some M&A activity that's gone on up in the area. The area in general has heated up a little bit because of that. As far as our operations go, we drilled two wells in the fourth quarter and completed those and got them to flow back right at the tail end of the year. Those were targeting one in the Niobrara and one in the Codell. We did different frac designs and had previously done in the area much larger design similar to our enhanced completions down in Windsor.

This area is having a lot lower GOR it just takes more time to clean out. So this is an area where we need more time before we can actually show what the production results look like. But we think sometime around the middle of the year, we’ll be able to update you with what the results there look like.

Irene Haas

And how does -- what else is going on in neighborhood and ultimately how do you feel about how the northeast extension might rank in your portfolio?

Mark Erickson

There are some other operators drilling up in the area of, one is the company that was recently acquired. The results that have been public from them and the Codell and the Niobrara, have been very encouraging. And those are the type of results we’re trying to replicate on our main Grover block just to the east. And if we’re able to do that then they will have fairly competitive economics going forward.

Operator

Thank you. And our next question comes from the line of Brad Heffern with RBC Capital Markets. Your line is open.

Brad Heffern

Just to follow-up on the Greeley and DCB questions. Can you talk about how you anticipate line pressures playing out after plant comes online? Obviously, you guys have the 45 wells that you highlighted that are going to come on and within this actually it seems like it would fill up relatively quickly. So are you pacing activity so that these 45 wells will come on this year and then you’re waiting for plan to 11 before there is more activity or how do you think about that?

Mark Erickson

Yes, that's how we’re trying to stage in our Greeley redevelopment. We have the big Triple Creek pad that obviously is already online and flowing. The next one we staged like we said to come online right around the time that the next plant comes. And from that point, we’ll be looking at the timing of the following plants in 2019 and trying to co-inside that with one of our next large pads in Greeley.

Brad Heffern

And then I'll ask a question about the regulatory environment. Can you talk about any thoughts on the challenges to raise the bar in the election later this year?

Russell Kelley

Just with regard to the situation you’re referring to, look there is a significant amount of case precedence in the circuit courts of holding this. And so that really gives us a high level of confidence that this will stand up. Happy to have the side bar conversation on the details, but we’re very confident on having that stand.

Brad Heffern

And any thoughts about the election?

Mark Erickson

So quite a days away from November, but we’re hopeful for what the results look like.

Matthew Owens

We’re watching it very carefully, but obviously the focus is on operations.

Operator

Thank you. And our next question comes from the line of Marshall Carver with Heikkinen. Your line is open.

Marshall Carver

Can you quantify the expected uplift from line pressure release when it comes in 3Q and how much do you expect production increase at that point and how quickly do you think it will increase?

Mark Erickson

So the main production increase is going to come from the existing wells, will be that big Triple Creek pad that we have in Greeley. We would expect that green -- all the wells that make up that green line, the other 20 wells on that pad to come up somewhere in line with where the blue -- the wells that make up the blue line are. And then we also expect to see a bump in our other PDP that is really our Windsor enhanced wells that have been online for a year or so now, and that would be on the slide just before that on slide nine. But the wells that make up that green line, you can see them bending over a little bit faster after about six months and was when we started choking those batch to make room for the higher percentage oil new pads that we were bringing on. So we would expect to see a slight uplift in the wells that make up that green line, but the majority will come from the wells in the pads that we have in Greeley.

Marshall Carver

And how fast do you think it would ramp when it ramps? Is it days or would it take a few weeks, so what should we think about that?

Mark Erickson

It should be fairy instantaneous as soon as that plant comes online and is running full time.

Operator

Thank you. And our next question comes from the line of Jeffrey Campbell with Tuohy Brothers. Your line is open.

Jeffrey Campbell

My first question was just -- and I’d like to step back a step, I think all the stuff about the constrained versus unconstrained wells is pretty fascinating. But the Greeley uplift that you just talked about and with the processing coming on in the third quarter. I just want to know how integral is that to your current 2018 production guidance? I mean is there a little wiggle room in the guidance in case if plant comes on little later than expected, stuff like that?

Mark Erickson

There is wiggle room in that. Like I mentioned, we’ve done a very detailed forecast for our budget and for our guidance on -- and risking for the plant timing, line pressures in the different areas of the field that are producing into that system. So we feel very confident that we’ve adequately covered those risks in the current guidance that we have out there right now.

Jeffrey Campbell

And just sticking to that subject, I just want to mention that I -- first that I heard you correctly earlier and just get your thoughts on this. I believe you said that the line constraints did not affect your ultimate AUR of the wells, but it certainly seems like that it could from time-to-time produce a differentiated financial effects since these other wells are able to produce harder and earlier. And I was just wondering what you think about that. It seems like there might be an extra lift through which to view capital allocation?

Mark Erickson

Yes, the wells that are unconstrained -- I mean they are a lot better financially when we’re able to flow them on the chokes that we would normally do so on. As far as reserves go, like coming in at year end when we had a bunch of wells showed back, obviously we weren’t able to get the full effect that we would have expected from the enhanced type curves. But once the wells are back or back to flowing at their normal capacities, then we should be able to see the wells come back on to the trends that they were prior to being constrained.

Matthew Owens

When you look at impact on wells, obviously when you look at greater returns been able to flow on constraint has a material impact. The other things that does as you look at one of the things that we were able to achieve like in our Broomfield development is we’re able to get -- take a few pads with a bunch of wells on them and scatter them out into quite a few pads with fewer wells, which is really going to accelerate our cycle times and improve the economics as well. So we’ve got the ability with our acreage position that we're going to be able to layer in short cycle time pads with some of the bigger cycle time pads in Greeley to smooth out our production profile and also with the smaller pads we can enhance the economics as well.

Operator

Thank you [Operator Instructions]. And our next question comes from the line of Jeanine Wai with Citigroup. Your line is open.

Jeanine Wai

Following up on the other question from David and Brad, you mentioned that you’ve got the 25 Greeley wells, ready to go for when comes online and then several others later in the year. But can you just provide us with frame of reference for how many Greeley type wells would still up plan…

Matthew Owens

How many Greeley type wells we’d fill it up?

Jeanine Wai

So the 200 capacity that should be enough for 35 wells or something like that. I'm just trying to get a sense of basically the mechanics of producer facing, because they’re four NPAs on again in there. You guys have a lot of big pads, we’ve heard from other operators so '18 on getting in. So just trying to get a sense for how many wells can actually get in when the same prospects at?

Mark Erickson

Jeanine, this is Mark. Just on a high level basis, I will let Matt kind talk about number of wells to fill up the base plant. But the northern system as well as the southern system is that integrate its system with multiple plants on it. So the first thing when you look at capacity in plant is the whole system, which probably has a deep line of 35% or more. So DCP with the plant coming online is going to be pushing a BC up a day. So when you're looking at 35%, you’re looking at almost $350 million a day of decline on the system over the course of a year. So that’s really the first big capacity that comes available as the decline. Then they are adding that incremental 200 million a day.

So we are looking almost a half of BC up a day of the incremental capacity that comes available with addition of the new plant. Specifically, when you start looking at how many pads does it in Greeley. Just one of the factors is where they are located. When you’re looking at the Greeley proper in north the pads tend to produce quite a bit more oil in the early stages. And when you move south into the core of Wattenberg field, the wells will get gassier. So location does have an impact on that. But Matt, I don’t know if you want to add something.

Matthew Owens

The Greeley wells that we’re turning online, they typically make between 1,500 and 2,250 mcf a day. So that might give you a little bit of data there figure that out. But we’re also hopeful that the midstream company is continuing working together like they have over the past few months and adding some bypass onto each other’s systems, for people that might have the excess capacity. So that has been happening the past few months even at the tail end of last year and we hope that that continues to happen throughout the rest of this year.

Jeanine Wai

And my second question is, and I can appreciate that you don’t have 2019 guidance out there. But can you conceptually talk about whether there is anything that would preclude you from adding another rig say around year end or early next year?

Matthew Owens

I would just say that we’re going to be remain very, very disciplined on our CapEx spending. And we’re going to play the long game. And what I mean by that is we see more value creation created not by achieving dramatic 70% growth in the future, we see the value creation coming from maintaining good steady predictable growth, which we can do with our high quality drilling inventory but at the same time, rotating our decline curve on our PDP base. We currently have probably in the neighborhood of 50% decline on our base production.

And if we can just rotate that from 50% to 25%, which is what I refer to as playing the long game, we create tremendous value in our PDP base, while at the same time maintaining a strong balance sheet we de-risk the overall business plan, which we believe will translate into Extraction being a much more interest leading and valuable investment opportunity.

Operator

Thank you. And this concludes today’s question and answer session. I would now like to turn the call back to Mr. Mark Erickson for his closing remarks.

Mark Erickson

I would just like to thank everybody for attending the call today. We thought 2017 was a great year, a transformational year for the company. We’re really looking forward to 2018 and continuing to deliver very strong results and looking forward to getting to that cash flow neutrality position and being able to more definitively answer some of your questions throughout the round returning cash flow to shareholders. So with that, we’ll conclude the call and thank you again.

Operator

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program and you may all disconnect. Everyone have a great day.