Cabot Oil & Gas Corporation
Q4 2018 Earnings Call Transcript

Published: 22 Feb 2019

[Operator:]

Good day, and welcome to the Cabot Oil & Gas Fourth Quarter 2018 Earnings Conference Call. [Operator Instructions]. Please note, this event is being recorded. I would now like to turn the conference over to Mr. Dan Dinges, Chairman, President and CEO. Please, go ahead.

[Dan Dinges:]

Thank you, Allison, and good morning. Thank you for joining us today for Cabot's Fourth Quarter 2018 Earnings Call. With me today are several executive members of team Cabot. I would first like to emphasize that on this morning's call, we will make forward-looking statements based on current expectations. Also, some of our comments may reference non-GAAP financial measures, forward-looking statements and other disclaimers as well as reconciliations to the most directly comparable GAAP financial measures are provided in this morning's earnings release. As some of you may recall, this time last year, we laid out a strategy for 2018 that was focused on

[Operator:]

[Operator Instructions]. Our first question today will come from Brian Singer of Goldman Sachs.

[Brian Singer:]

You've been very upfront on the return of capital to shareholders, committing to at least 50% of free cash flow. How do you think about the, at least or the plus in that, as it relates to 2019 cash balances, seem to have kind of come down here at the end of the year? And maybe you could also comment on what you see as the right sustainable cash balance as you think about trying to manage the plus and the 50% plus of returning free cash flow to shareholders.

[Dan Dinges:]

Yes, by design, we brought our cash balance down, felt comfortable with the infrastructure buildout, Atlantic Sunrise, the commission with those two power plants that -- with that and our ability to grow into deliveries on those infrastructures that our cash flow was not a -- not just an assumption, but it was a reality. So we felt comfortable not only drawing down that cash balance but repaying the $300 million of debt and increasing the dividend twice this last year and with the $1 billion of buyback. Right now, with the free cash flow generation that we anticipate in '19, we've kind of layered in a base assumption, Brian, at the $2.75, and the plus would come, if in fact, we realize the $2.90, which the strip sits at today, if we realize the $2.90 then -- or something above that, then we're going to do what we've done in the past, and that is to deliver some of the funds back to the shareholder. We'll make a decision whether it's in the form of dividend or a buyback. But it's not our intent, with our confidence level of the cash flow we generate, it's not our intent to leave a lot of cash on the balance sheet.

[Brian Singer:]

And then my follow-up is on the midstream front. I don't know if you or Jeff are teed up for just the latest and greatest update on the various timing of projects and anything that's new that's coming onto the chalkboard, but that would be great, if that's a possibility.

[Dan Dinges:]

Yes, I'll flip it over to Brian -- I mean to Jeff, Brian.

[Jeffrey Hutton:]

Yes, I think on the midstream, it's relatively quite as we await some additional ruling with the PennEast. I can tell you if there are some new projects that have been laid out in front of us over the last few months that we're interested in. I don't think a lot of this has reached out into the public domain yet, but still a lot of movement on midstream projects. Additionally, I think even -- maybe more importantly is the additional, in-basin demand project that we're viewing. There's quite a bit of activity, not just in Susquehanna County but in that Northeast corner of Pennsylvania, with additional projects that are being developed to keep gas in the basin. And that's been exciting to watch as well.

[Brian Singer:]

Can I ask, on the new projects, are you talking about those to move gas to the New Jersey, New York markets, to the Southeast markets or dare I ask, to the Northeast markets? Yes.

[Jeffrey Hutton:]

Yes, so I think, a couple of them will do both, and the -- I don't think anyone has given up on building pipe out of Pennsylvania into either New Jersey or New York and additionally, moving gas back down into the South. But I think the pipelines, we'll be talking about those in the next few months.

[Dan Dinges:]

Yes, Brian, I'd like -- yes, I'd like to add also on that point that not only would gas move out of basin, like Jeff is referring to, there are also a number of in-basin projects that he alluded to that we continue to work on that we think would not have it on the long-haul pipes but would have it from the tailgate of our gathering system. And we think that is meaningful to simply from the standpoint of how it assists in balancing the basis up there. I would also like to point out while I take this time as some of my colleagues here want me to maybe not expand on questions, but I would point out that in the New York Post today, there was an interesting article on Cuomo and the results of his crusade against natural gas and the beginning of some of the issues that New York is experiencing up there, experiencing the farm where it is starting to hurt small businesses, it's starting to hurt the development of new housing. I think it's clear that businesses are going to be turning away from New York. And with all of this, including the largest utility in New York representing that they will no longer accept applications for natural gas hookups, and that's kind of it, beginning March 15. I think these are all the early signs of -- that a policy that is creating a significant calamity in New York. And I think it'll continue to have companies evacuate from doing business there.

[Operator:]

Our next questioner will come from Jeffrey Campbell of Tuohy Brothers.

[Dan Dinges:]

Let's move on.

[Operator:]

The next question will come from Michael Hall of Heikkinen Energy.

[Michael Hall:]

Just curious, I guess, on -- as I was looking at your 1Q guidance, it seems pretty clear you guys aren't really like leaning into the winter market, let's say. Was that a view on the market stability to take the volumes are more a function of just the strict adherence to your approach on capital discipline?

[Dan Dinges:]

Have our scheduled program. We have the time completion, Michael. When we get our pads -- all the drilling completion done on particular pads. And at various times of the year, just sequentially, it -- they come on at various different times, and it gets a little bit lumpy. And so there's no particular master design on where we are in the first quarter.

[Michael Hall:]

Okay. And do you have any sort of curtailed volumes that you could theoretically open up for opportunistic accessing of the market? And I guess, for lack of a better way to put, are you kind of running full house in any given period?

[Dan Dinges:]

No. We're producing what we can. The curtailed, if you will, volumes would be volumes that are adjacent -- that are wells that are adjacent to completing pads. We do shut in our existing production on some of the surrounding patch, surrounding wells while completions are going on to help avoid frac hits and things like that. So -- but as far as having a block of curtailed volumes, we do not have that, and I don't anticipate anybody in the industry has that.

[Michael Hall:]

Okay, great. That's helpful. And then I guess last for mine is just on the Upper Marcellus. I'm just curious, just exactly how much do you think you will allocate in the 2019 program on the Upper Marcellus? And are there any changes in completion design associated with incremental productivity?

[Dan Dinges:]

We have a handful of wells that we'll drill, and whether 10, 15 -- that's kind of in the key right now. I don't have the exact count in front of me, Michael, on the status of the drilling completion of the ones that we have scheduled for '19, but we had a -- we're just a good sample pool of Upper Marcellus completions.

[Operator:]

Our next questioner will come from Charles Meade of Johnson Rice.

[Charles Meade:]

I wanted to pick up. You touched on this a bit in your earlier question, but I wanted to explore a little bit more. When I look at the -- you guys have a slideshow on how the basis has improved up to the Northeast. And when I look at that, it looks to me that delivering volumes -- you've moved all these volumes on the Atlantic Sunrise, but delivering volumes into the local market, looks -- it certainly looks more attractive than it has for most of the last in your few years. And so -- but it -- my read on what you guys are doing is you guys are electing not to do that because you're keeping your CapEx low, and looks like you guys are -- or you've committed to doing more cash return to shareholders. So can you talk about how you went through that decision? I know it's something you look at all the time, but how was the evaluation of delivering the incremental volumes into the local market look to you right now?

[Dan Dinges:]

And I'll flip to Jeff to make commentary on the basis. But one quick comment is, with Atlantic Sunrise coming on, we knew we were going to transfer those volumes out of basin, with a couple of long-term contracts that we were fulfilling and price points out of the basin that were better than in-basin pricing. So we're doing that. On the question about backfilling. We saw contemporaneous with the commissioning of Atlantic Sunrise and these power plants. We saw a fairly drastic narrowing of the differential. And with that -- that improved -- not only did we have an improvement by the gas that we moved on the new infrastructures and to the power plants, but that dramatic improvement in the basis also enhanced every other molecule that we were still selling into the basin. So with that uplift and the rest of our gas, we feel comfortable that maintaining that volumes we're producing and having just a measured growth by our capital allocation and allocating back some of our free cash and buying back shares and having a per share metric component to growth, we think that fits what we're trying to accomplish on improving realizations throughout not only the basin but also where we're moving gas outside the basin.

[Jeffrey Hutton:]

Without getting too far into the weeds on this, we -- Atlantic Sunrise, the reaction in the marketplace was pretty much what we expected. Of course, Cabot did redirect a large amount of volume from other pipes to fill Atlantic Sunrise. On the other hand, the other half, I guess, of Atlantic Sunrise, those volumes were being delivered into the Leidy system directly. And so what we saw was a large amount of gas leaving the lighting system as well as Cabot gas leaving the Leidy system, but then that influence in that Leidy basis fell back into the other pipelines as well. And then along at the same time, we have a number of in-basin projects, not just Cabot-related but other producer-related projects. So it was somewhat of a perfect storm in a very good way, this fall, for the pricing and the basis in Northeast PA.

[Charles Meade:]

Got it. You guys -- and then, if I could also ask Dan, back on the Upper Marcellus, what would you guys need to see in terms of well productivity or whatever the metric -- development metric for you? What do you need to see from those Upper Marcellus leases before you decided to perhaps codevelop those with Lower Marcellus locations and save on the surface and mold costs and things of that nature?

[Dan Dinges:]

Well, I'll make a couple of comments. First, I'll make a comment regarding our comfort level since we received a number of -- not a number, a couple of questions regarding our Upper Marcellus and how do you know it's distinctive. And I'm going to just give one example. We have a number of examples that we could give to you, but I'll give you one example that most people are not going to have any problems understanding how we have the conviction that we do. We laid 2 -- this -- recently, we laid two Upper Marcellus wells in an area that we had prior completions on our -- in our -- in the Lower Marcellus. And in this specific example I'll give you, we had two Lower Marcellus wells that had been producing for an extended period of time. We put two Upper Marcellus wells 400 feet, get that context, 400 feet from two Lower Marcellus wells that had produced a long time. And we completed those two Upper Marcellus wells that were 400 feet from these two Lower Marcellus wells. It just so happened to be the two Lower Marcellus wells that we chose to do this experiment on have each cum-ed over 20 Bcf. Okay, so we laid two Upper Marcellus wells, 400 feet from two wells that had cum-ed each 20 bcf. Those Upper Marcellus wells came on normally as you might expect. The early time production from those Upper Marcellus wells have actually fit a curve. And again I'm going to caution the comment here on a curve fit with very little data, but those two Upper Marcellus wells came on fitting a curve of 3.3 Bcf per 1,000 and 3.7 Bcf per 1,000. I'm not saying that that's what we're going to go to. So don't take it, and I hope nobody comes and ask about what about the 3.3, 3.7 Bcf, 5,000 EUR. That might be our poster, Charles, from this point forward. I'm just giving you an example of our confidence level. If there's any place we would have seen some issues, it would've been where we had produced over 40 Bcf, 400-something feet away from a couple of Upper Marcellus. So that's -- so box commentary in that. What was the rest of your question?

[Charles Meade:]

Well, what was...

[Dan Dinges:]

Scott wants to -- Scott's been raising his hand so...

[Scott Schroeder:]

But Charles, I think back to the -- at what point would you go to taking a word out of the West Texas, the -- and [indiscernible] playbook be the cube kind of concept. The other thing that plays into that is what is the takeaway capacity in that part of our field at this point in time? What we wouldn't want to do is do all of the lowers and the uppers and then be constrained because we wouldn't be able to get that gas to market. And while -- in addition to being the most efficient to the lowers then the uppers and come back, do -- and do the uppers later. And Dan's example right now highlights that there is no degradation when we came back. That's still the primary focus of how we're going to do it. The really only downside is the mold cost you mentioned because we're building the pads where we can come back on them and all that kind of stuff. So there's not a lot of lost efficiency. What we don't want to do is instruct Williams to put a huge pipe out there that will never be filled again after the initial production. That's just not efficient from that side of the equation. So that's kind of the dynamic. We will do some science test, like Dan highlighted earlier, where we'll do -- we had 10 or 15 that we think -- I think that's the latest number in the '19 program. We did 9 in the '18 program. We'll continue to do a few handfuls of these as part of the science project going forward. But in terms of full develop -- the full pad outside and maybe 1 or 2 for science purposes, it's still most efficient to do what we're doing.

[Operator:]

The next question will come from Mike Kelly of Seaport Global.

[Michael Kelly:]

I just wanted to check in with you guys on the Constitution pipeline. RBN had an article out this week that at least expressed some sort of hope in the revival of that project and just wanted to get your perspective on that and your thoughts.

[Dan Dinges:]

Well, we have maintained our efforts to get some movement in Constitution. The D.C. Circuit Court of Appeals had a ruling -- a favorable ruling in a similar case, a fact-patterned case, that was favorable to Constitution's fact pattern. And the FERC is there's still consideration out there, I guess, and a sense on maybe what might happen next. And we think the ruling in the D.C. Circuit Court of Appeals is again favorable if you didn't take the fact pattern that we have in Constitution. And that has to do with the waiver consideration. So we hope we'll have at -- maybe at some point in time another time to have this addressed, and we continue to work on that.

[Michael Kelly:]

Okay. Any extensive timing on that? Like what the next step is for us to look for?

[Dan Dinges:]

Yes, we have -- with all the uncertainty, I'd be speculating, Mike. But I would think that -- I would hope that sometime in the first half of '19 that we would have some additional consideration from the courts, from FERC or something that might opine on this.

[Operator:]

Our next question will come from Leo Mariani of KeyBanc.

[Leo Mariani:]

I don't want to harp too much here on the Upper Marcellus, but I know you guys, I think, said you had nine wells that you get to do work on in 2018 not ready at this point kind of come out with anymore defined EUR estimates. But out of curiosity, I mean, how much production history do you think you need to see on some of those wells to give you guys a better sense of what the Upper Marcellus EURs look like? And what -- how old are some of the kind of wells that you frac-ed in 2018? Just trying to get a sense of how much history you have now and how much you think you need to give yourself a little better handle on it.

[Dan Dinges:]

We need a year, 1.5 year and the '18 wells are -- none of them are a year old yet.

[Leo Mariani:]

Okay. That's helpful. And I guess, just turning to the exploration side. I guess obviously, you guys kind of abandoned your recent effort here of late. I just wanted to get a sense, I mean, is there a continued appetite for Cabot to kind of look at other plays either this year or next to try to continue to sort of build the company? I just want to get a sense of your thoughts on looking at other plays. Obviously, you've got a tremendously higher-rate of return opportunity right now, which is a pretty high bar. So how should we think about that going forward?

[Dan Dinges:]

Yes. Right now, we have no interest in allocating any additional capital to exploration. So the answer today is, that's where we stand.

[Operator:]

Our next questioner will come from Doug Leggate of Bank of America Merrill Lynch.

[Douglas Leggate:]

I'm just wondering if you could give us an update on your exploration ambitions beyond obviously being used today. What's next? Are you going to stick with the Marcellus on a go-forward basis?

[Dan Dinges:]

You might've been -- might not have heard the answer, previous call, but we're not going to allocate anymore capital to exploration at this time, and that's kind of where we are.

[Douglas Leggate:]

Okay, sorry, I did miss that. I apologize. My follow-up is really just a quick one, I guess, because we haven't really asked your opinion on the gas market for quite some time. And obviously, after the first -- the fourth quarter strength that we saw, I think that some folks were of the view that the idea of just-in-time production was probably not the right model going forward, and we are, in fact, going to have a more resilient outlook. I'm just wondering if you could give us your prognosis on how you see things playing out. Will your plan bear it? And I'll leave it there.

[Dan Dinges:]

Couple of moving parts in that, and that's a -- that can be a long-winded response. But a couple of moving parts in the way I look at it is, one, I think it is imperative that our industry rationalized the market in a way that is prudent for all shareholders. And I think there's -- there are signs that rationalization is taking place, even though from October to current, there's -- seems to be more rigs working today than there were back in October. We did see in December and January, a little bit of reduction in -- at least up in the Appalachia area, a flattening or a reduction in production up in that area. So that would be helpful. But in looking at the demand side of the equation, I'm optimistic that there is going to be another 3 or 4 Bcf a day going offshore by commissioning of the LNG facilities. We're seeing incremental demand that is needed up in the -- up in New York and up in the Boston area. When utilities now in Boston are talking about not taking application for new natural gas hookups. That means that demand is increasing, and there's a need for additional natural gas up there. So I'm encouraged by incremental demand up there in that particular area. So -- and I also think that it's proven from your side of the equation, Doug, that if in fact there's reward on value and there is expectation that value would be returned to shareholders in the form of buybacks, of dividends and that's meaningful, then that is going to help assist with the market as opposed to some that keep focused on growth at the -- at all cost. And so I think all of this is part of the forward look on natural gas. But I also think that natural gas plays a role on any of the renewable footprint out there, natural gas better be part of the equation. Otherwise, your responsiveness to the insecurity of a delivery of energy is going to be challenged.

[Operator:]

The next question will come from Jane Trotsenko of Stifel.

[Jane Trotsenko:]

Dan, could you please expand on what drove the 19% year-over-year increase in the crude reserves in 2018? It looks like the increase in results is well above the three year average run rate. And I was just curious if it's due to the outperformance of the existing wells. So is it like the recent well results have been particularly strong or something else that would explain that?

[Dan Dinges:]

All right. And I'll -- Steve Lindeman is in here, and he is responsible for our reserve bookings, and I'll let him cover that. Thanks for the question.

[Steven Lindeman:]

So a part of what drove most of our revision this year was drilling longer laterals than we had modeled in our '17 reserve report. As time's progressed, we've upped our lateral length. Our average pipe was about 5,500 feet. And our wells that we drilled were in the 8,000-foot range.

[Jane Trotsenko:]

Okay. Got it. Got it. And then my second question is for Jeff. Jeff, could you please expand a little bit on fixed-price sales that account for 16% of the sales mix in '19? Is it something that we should expect to take place in 2020 plus as well? And how do you think the pricing for those volumes will evolve over time?

[Jeffrey Hutton:]

Jane, I'm going to grab the table real quick because I'm sure -- thank you, Matt. You're asking about the change on -- in 2019 on the NYMEX portion?

[Jane Trotsenko:]

Yes. So you have fixed-price sales. So it seems to me that those are term sales, but I'm not sure if those are term sales that you roll over maybe on a quarterly or an annual basis. And I'm just curious how that portion will evolve over time in terms of volumes and pricing?

[Jeffrey Hutton:]

Okay. Well, on the fixed-price portion, that's of course a combination of some of our contracts that have fixed-price forwards in them. And so going forward, that piece of that fixed price, 16%, will remain static. However, another part of the fixed-price is just from opportunities we've seen in the marketplace. So I would expect that to continue to be dynamic. If we have opportunities to convert some NYMEX or some index-based pricing to fixed price, we will take advantage of that. So that one is more of a moving target that we can't really elaborate on going forward in the '20, '21 or '22.

[Jane Trotsenko:]

I see. I see. And in terms of pricing, how are those volumes priced? Is it -- should it -- should we think about them in terms of comparable pricing to '19? Or can you comment on that as well?

[Jeffrey Hutton:]

Now that's built into the overall -- how we calculate the overall basis differential to NYMEX, looking forward. So it moves around.

[Operator:]

Ladies and gentlemen, this will conclude our question-and-answer session. At this time, I'd like to turn the conference back over to Mr. Dinges for any closing remarks.

[Dan Dinges:]

Just briefly, I appreciate everybody's interest in Cabot. I think, it is interesting, and I reflect on the release we've made. And looking at our -- not only our press release but the comments in this morning's report, it's interesting to have an E&P company make a report that does not talk about how much a particular pad has come on or what a zone has done, what a yield is on the well but talk strictly about what type of financial performance we can deliver to the shareholders. And I think that is, certainly, what we're hearing is the shareholders are very interested in value and value creation. And I hope it is getting a little bit agnostic that just because we do it with natural gas does not mean that we have a flawed company. So with that, Allison, I appreciate the interest. And we'll conclude the call.

[Operator:]

And thank you, sir. The conference has now concluded. And we thank everyone for attending today's presentation. You may now disconnect your lines.