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Ladies and gentlemen, thank you for standing by, and welcome to the Q4 2019 Black Stone Minerals, L.P. Earnings Conference Call. [Operator Instructions] Now I’d like to turn it over to Mr. Brent Collins, Investor Relations. You may begin your conference, sir.
Thank you, John. Good morning to everyone, and thank you for joining us either by phone or online for Black Stone Minerals’ fourth quarter and full year 2019 earnings conference call. Today’s call is being recorded and will be available on our website, along with the earnings release, which was issued yesterday afternoon.
Before we start, I’d like to advise you that we will be making forward-looking statements during this call about our plans, expectations and assumptions regarding our future performance. These statements involve risks that may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements. For a discussion of these risks, you should refer to the cautionary information about forward-statements in our press release from yesterday and the Risk Factors section of our 10-K, which will be filed later today.
We may refer to certain non-GAAP financial measures that we believe are useful in evaluating our performance. Reconciliation of those measures to the most directly comparable GAAP measure and other information about these non-GAAP metrics aredescribed in our earnings press release from yesterday, which can be found on our website at blackstoneminerals.com. On the call this morning are Tom Carter, Jeff Wood, Holbrook Dorn, Brock Morris and Steve Putman.
I’ll now turn the call over to Tom.
Thanks, Brent. Good morning to you all on the call this morning. I’m going to begin by recapping 2019 and speaking about the beginning of 2020, which I must say is quite a snapshot of a rapid change in the oil and gas industry from the beginning of 2019 to the beginning of 2020. So here we go.
From an activity standpoint, 2019 was a busy year with the company adding 19.3 net wells for the year. It’s a little bit shy of 21 wells that we had in 2018, but it’s – but it isn’t surprising given the slowdown in the industry activity that occurred throughout the year. We are benefiting from the continued industry attention in the Permian, where we’ve added 6.7 net wells in the Midland/Delaware program in 2019 compared to five in 2018.
We saw 3.5 net wells added in the Shelby Trough-dominated Haynesville program, which was weighted to the first half of the year, for sure, and is higher than the 2.8 we added in 2018. We’ve discussed previously how activity in the Shelby Trough slowed during the year in response to rapidly declining natural gas prices. So it wouldn’t shock anyone that the completion in the Haynesville slowed in the back half of 2019. We continued to see well adds in the Bakken/Three Forks and Eagle Ford with 2.3 and 1.3 net wells added in 2019 respectively.
At the end of the fourth quarter, we had a total of 95 drilling rigs operating on our acreage, two-thirds of those rigs were in the Midland/Delaware. Interestingly, approximately 15% of our rig count is active in programs outside of the higher profile resource plays, which tells you that despite the negative sentiment surrounding the oil and gas industry today, there continues to be drilling activity even outside the big shale plays.
In terms of permitting activity, Black Stone saw roughly 1,875 permits added on its acreage in 2019. That’s 5% more than we saw in 2018, and over half of those permits were in the Midland/Delaware. Approximately, 450 horizontal permits were added on our acreage during the fourth quarter, which is basically flat with the third quarter.
On the acquisition front, we did $44 million of acquisitions in 2019, most of which was done in the first half of the year. I talked about this a little on our last quarterly call, and we have become much more selective about what we look at in terms of acquisitions. We’re being a bit more cautious. And while we’re in the mode, we will prioritize paying down debt with our excess cash flow.
In the Shelby Trough, discussions are ongoing regarding development of that important asset. It’s a difficult time to be negotiating transactions in natural gas deals right now. And it is a very challenging time to put those things into play because, typically, folks that are willing to come into that play are looking for very long-term commitments with lower royalties, and we’re trying to balance maintaining activity currently with optionality in the future.
We remain hopeful that our efforts will result in bringing development capital back to the area where we are the dominant mineral owner with almost 50,000 net minerals in a resource base that we estimate to contain over 6 Tcf of natural gas. We are also seeing renewed signs of life in the East Texas Austin Chalk play, very early stages, I would say, where recent positive drilling results have spurred discussions around some of our extensive acreage position there. We don’t have any new activity in the Shelby Trough or the Chalk in our 2020 guidance that Jeff will cover in a moment. But it’s encouraging to see producers’ interest in the areas where we own concentrated mineral positions, and we think that interest should only grow with some degree of price recovery.
From a financial perspective, we are in a pretty good shape. Our focus on balance sheet strength resulted in outstanding borrowings of $394 million as of year-end, which is down by over $40 million from midyear and our current debt-to-EBITDA ratio stands at a very healthy 1x.
So while Black Stone’s business is fundamentally solid, we have to acknowledge that we’re in a tough industry environment. Rig count has dropped by 27% since the end of 2018, as most operators are now trying to live within cash flow and have moderated their activity. We’re in February, the prop month contract for natural gas has been well below $2 since the start of the year and the forward strip stays below $2.50 for the foreseeable future. With all this as a backdrop, we have made some – had to make some tough, hard choices.
First, as we previously reported, we made the decision to decrease the distribution attributable to the fourth quarter to $0.30 per share, even though we had very good coverage. If current conditions persist, we expect to target a total payout of $1 per share for 2020. This should allow us to further reduce outstanding borrowings during the year through retained cash flow. We know the importance of distributions to our unitholders, and we believe this path balances our historic – history of conservative balance sheet management, while preserving a meaningful return to our owners.
Second, last night, we announced that we will be significantly reducing our G&A costs through lowering executive compensation and reducing the headcount of our organization by approximately 20%. It’s really difficult to talk about how tough it is to part with colleagues and friends. It’s an incredibly difficult decision because of the impact on those employees affected. In particular, I’d like to thank Holbrook and Brock and Brent who are in this – on this call today for what they’ve done for many years for our organization as well as all the other folks who’ve been affected by this change.
With that, I’ll turn the call over to Jeff.
Okay. Thank you, Tom. Good morning, everyone. I’m just going to quickly cover our guidance for 2020 and give a little bit more color on our balance sheet, then we’ll open the call up for questions.
As Tom mentioned, despite some of the current headwinds, we’re coming off another solid year in 2019. Our royalty volumes were up 14% from 2018 and we generated $400 million of adjusted EBITDA for the year. As we look to 2020, we expect royalty volumes of 32,000 to 34,000 BOE per day. We base that on our producer feedback, on known permits and on other data that we’ve got a good line of sight on. It does not include any contributions from acquisitions we may make during the year or from areas like a Chalk, which have real potential, but where we don’t have a clear view on activity yet.
Our royalty volume estimate represents a 9% decline from 2019 volumes and slightly ahead of what we reported for 2018. We expect we may see some declines in our relatively mature Bakken and Eagle Ford positions, but most of that decrease is driven by reduced activity in the Haynesville where we saw a huge spike in activity in 2018 and 2019 that was the main contributor to our royalty volumes growing by 65% over that time.
With the decline in gas prices, we’ve seen some of our larger producers pause activity. The resource base there remains, of course, and we believe it competes with the best gas play economics in the country, especially given the proximity of the Gulf Coast industrial and LNG export markets. So that area is going to continue to be an important driver of our long-term cash flows. But like all gas plays, it is challenged right now.
We expect working interest volumes to decline by about 25% in 2020 relative to last year. That is by design as we intentionally stopped investing in that part of the business in 2017. As a result of all that, we expect royalty volumes to increase to almost 80% of our total production volumes in 2020. The other components of our 2020 guidance are generally in line with what we experienced for 2019. That’s, of course, with a notable exception of our general and administrative expenses.
The oil and gas industry is facing pressure on a number of fronts right now. One of the great things about being a minerals company is we don’t incur the capital or the operating cost that can weigh down the E&P sector at times like this. The downside is that there’s only so many levers we can pull to control our volume growth and distribution levels. We try to buy in the right areas, and we promote our undeveloped acreage through creative deals with operators. The other lever that we have to pull is around our internal G&A costs. As Tom discussed and as you probably saw in our earnings release yesterday, we’ve taken big, decisive and, frankly, really painful steps to reduce our cost profile in the face of weak natural gas prices and more constrained E&P spending.
Our total G&A guidance for 2020 is $39 million to $43 million for the year. At the midpoint of that range is a 35% reduction from our total G&A in 2019. We expect to reduce both cash and non-cash G&A costs by over $10 million each for 2020. As Tom mentioned, the primary areas contributing to that reduction are lower executive salaries and bonuses; lower executive long-term incentive grants, which will limit share count dilution; and the headcount reductions that Tom talked about. We do expect to incur a onetime charge connected with these reductions of about $5 million. I think that’s going to be recorded in the first quarter of 2020. I want to make clear that the guidance range for G&A does not reflect that nonrecurring charge.
Finally, Tom mentioned our focus on the balance sheet. We had coverage of 1.5x on the fourth quarter distribution that translated in almost $30 million retained cash flow. Our total debt at year-end was $394 million or 1x our 2019 EBITDA. And that debt amount was down to $362 million prior to paying the distribution yesterday. We expect to continue to maintain healthy coverage ratios throughout 2020, which should further our debt reduction efforts and enhance our overall financial flexibilities when these markets rebound.
With that, John, I think we’ll open the call up for questions.
[Operator Instructions] So we have a question from Derrick Whitfield from Stifel. Your line is open.
Sure. Thanks. Good morning, all.
Good morning, Derrick.
Regarding your royalty production outlook, could you speak to the net well addition implied in your 2020 plan and note the amount of new net wells assumed from the Haynesville?
Well, Derrick, this is Jeff. I don’t think we’ve broken down expected net wells by specific area. Maybe we can follow up with you on that. I mean as Tom mentioned, the guidance doesn’t, for example, in the Shelby Trough, even though we’ve got conversations ongoing about bringing new operator or operators into that area, our forecast does not assume any net wells into that area. So it’s really the Louisiana, Haynesville that we’re talking about. There were 59 total new wells added in the Haynesville in 2019, which was a big year of activity for us. So we’re certainly expecting that to come down. But again, I don’t know that we’ve given that specific guidance by area at this point.
I’d just – I’d add to that, that just from an upside possibility and I’m not saying it’s a probability, our numbers of wells in the Haynesville in our forecast are de minimis, especially in the Shelby Trough like zero. And there are quite a few DUCs out there and there are quite a few wells that we could get drilled by incenting operators through reduced royalties, but we are still playing that out. And you can always know in our business as these cycles are what they are and gas prices go down, people quit drilling and then eventually gas prices go up, which causes more drilling. How that cycle plays out? You can read a lot about that in the financial press, and I won’t try to suggest a path for that, but there has been a significant amount of capitulation in the gas side as the drilling is falling off at a very rapid pace, which means there’s going to be a rapid decline.
That makes sense. And perhaps staying on that topic, specifically, could you speak to broadly the market interest at present and your motivation to release the acreage in a sub-2 Mcf environment? I certainly sensed a bit of tension in your earlier comments as it relates to your desire to run out there and release it but, certainly, it’s high quality acreage that has a market value.
I’ll leave through that this way. We’ve given quite a bit of thought and negotiation with industry on that and we’ve talked about it a lot at the board level. And our current thought is that we will move towards putting some of our acreage into play this year in the Shelby Trough and we will keep certain parts of it out of play, and that is primarily to give us more exposure to the upside when the gas markets do come back when – if they do, we’re – and also on the downside, adding cash flow to the system in 2021 and 2022 to hedge distributions. So we’re really – we’re playing it in a hedged manner. We’re going to keep a fair amount of exposure to the upside, but we’re also going to put some acreage into play now.
It’s very helpful. Thanks for your detailed comments.
We have a question from Pearce Hammond from Simmons Energy. Your line is open.
Good morning, and thank you for taking my question. Jeff, by our modeling, Black Stone is fine from a leverage standpoint during this downturn. But I wanted to understand how you plan to manage the level drawn on the credit facility. It looks like you’re approximately 55% drawn currently. And do you expect to stay at that level over the next year, given the added flexibility from the distribution cut and the G&A reductions? Or do you think that percentage could move lower? And then finally, just general thoughts if you can provide them on the upcoming spring borrowing base redetermination?
Sure. Pearce, generally, the main metric that we – well, there’s a number of debt metrics that we focus on. One, is, as you mentioned, how much we’ve got drawn relative to our borrowing base and, therefore, how much liquidity we maintain just on a given time. And the other is just making sure that our amount of drawn borrowings really matches up with the way the business is performing. And that’s why we focus on debt to EBITDA metrics.
So we have historically run in that sort of sub-1.5 times, really kind of 1 to 1.2 times leverage ratio. I think we would intend to continue to stick in there – in that range. In terms of just sort of absolute borrowings and especially absolute borrowings relative to the borrowing base, certainly, with where prices have gone, we think there’s going to be pressure not just on our borrowing base, but on the – across the entire industry. There’s been a pretty unusual bank market where some of these E&P bankruptcies have actually significantly impaired the first lien guy’s ability to recover capital, and we think that, that may make banks just overall in the space a little more cautious in their lending levels. So this is all just part of this conservative approach that we’re trying to take to the balance sheet.
So we have thought about 2020 distribution levels in a way that will allow us to continue to maintain pretty meaningful coverage levels so that we can move debt down. And so that either is going to benefit us and just making a step more comfortable with debt levels as they are outstanding or it sort of loads the spring a bit for when acquisition or buyback opportunities present themselves or when this market turns around, we think having a very clean balance sheet will put us in a position to compete for those assets in a good way. So it’s not so much a specific percentage of the given borrowing base, but we’re certainly taking a – maybe even more conservative stance just given what we think could be some difficulties across the sector over both the spring and fall redetermination season this year.
Thank you, Jeff, for the detailed answer. I appreciate it.
We have a question from Harry Halbach from Raymond James. Your line is open.
Good morning, and thanks for taking my questions. My first question is in regards to dividend coverage. Over the last five years, you all have been around 1.3 times coverage. Is that what we should assume going forward? Or is there anything that you think would change that?
Harry, this is Jeff. I think in that 1.2 to 1.3 times range is where we’re really comfortable. We obviously ran a little higher than that this past quarter, just to push debt levels down a little bit more. But I think in general, that’s a very comfortable range for us.
Thank you. And then my next question is in terms of the production, you all only gave annual guidance. Would you expect those declines to be more felt in the first half of the year and kind of moderate in the back half or just any general comments on the cadence?
Yes. Well, I think it really – Harry, just depends in part on some of the timing of DUCs getting turned over and then just to see where commodity prices go, what I say is we would continue to expect that our working interest volumes would fall off more since we’re not investing in that part of the business at all anymore. So I think you’d see those production volumes come down and our overall percent royalty – our royalty as a percentage of total production continue to trend up during the year. So absent that, royalty volumes are certainly more stable, but we are going to be in a bit of a down dip here just to some of these existing Shelby Trough volumes play out. And assuming we bring a new operator in, which as Tom said, that is the intention for this year. It’s probably going to be very late 2020 or more likely 2021 before those new wells start to come up. So maybe slightly front-weighted during the year. Certainly, our working interest volumes and maybe a bit on royalty as well.
Great, thanks. That answers all my questions. I really appreciate it.
Next, we have Jeffrey Campbell from Tuohy Brothers.
Good morning. I just wanted to ask two questions surrounding the working interest and of the business. The first one, just broadly, is the withholding of the investment and the working interest wells. Is that a permanent shift or is that temporary until commodity prices improve?
No, Jeff, this is Jeff. That is more of a permanent shift. I mean, I say that. So where we’ve used working volumes in the past is really to promote or accelerate our royalty volumes. So for example, most of our working interest volumes today come out of the Shelby Trough where we participated alongside XTO in 2015 and 2016 to really kickstart that program. In 2017, we farmed out all of those working interest volumes, which is why that’s declining by design, as we mentioned. If we had an opportunity to where we thought participating in working interest volumes would promote or accelerate royalty volumes again, then we’d take a hard look at that. But from just an overall business standpoint, we are a royalty company, and we’ll continue to think about working interest volumes as a way primarily just to promote that side of the business.
Okay. And then my follow-up. I think you may have just answered it. My follow-up was, do you have any other non-working interest in the portfolio other than Shelby Trough that might be fungible assets that you would consider selling? And I think you mentioned earlier, you might do sell some stuff in Shelby. So we realize there’s a trade-off between debt reduction and cash flow sold. So I’m just kind of interested in your thinking about that as a general premise.
Yes. Well, we’ve got working interest optionality across several parts of our portfolio, and we routinely will sell individual working interest in a given well when those opportunities come up. So that’s just part of day-to-day business and will continue to happen, but it’s not of a scale that really impacts the business. And then, Jeff, I just wanted to make clear, we have no intention of selling anything in the Shelby Trough. Now – we sold our working interest rights to outside capital providers in exchange for overrides and back-ends, but we remain very, very bullish on the Shelby Trough and expect it to be a meaningful contributor to long-term volumes. So there’s no intention to sell any mineral acreage in that area.
Well. Okay, great. I appreciate that color on the last point. Thanks very much.
Next, we have Phil Stuart from Scotiabank.
Good morning, guys. Appreciate you all taking the time. I wonder if we could talk a little bit about hedging. Obviously, you all are very well hedged in 2020. Just trying to think, obviously, a very challenging commodity price environment that we’re dealing with today. So just wondering how you all are about hedging into 2021. And maybe what kind of – if there’s a target percentage of oil and gas production that you’re looking to hedge by a certain time in 2020, for 2021? Just kind of trying to get the updated thoughts there.
Yes. Well, Phil, as you know, we would normally at least have established some initial 2021 positions. It’s been such a difficult forward market that we haven’t done that yet. But all of these – the distribution expectations that we’re trying to lay out today and our forecast, obviously, just run off the strip. So I would think at some point here relatively soon, we would start adding positions for 2021 just sort of opportunistically. But yes, we would certainly not intend to go into 2021 unhedged. It’s just been – we’ve been a little more hesitant than normal just given how weak the forward prices have been to date.
I would just add sort of tongue in cheek. That’s one good way to get the prices to go up is to add some hedges.
Understood. And then I wonder I’m sure this will be kind of out in the 10-K whenever you file that, I believe, later today, but just curious if you all could give a breakdown of production by area, maybe just overall Permian, Haynesville, Shelby Trough, Bakken and Eagle Ford. It’s the percentage of total production in each area. If you have that handy?
Yes, we can do that. For 2019, the Midland/Delaware was about 13%, 14%; the Haynesville/Bossier, both Louisiana and Texas was around 0.5%; Bakken was about 10%; and Eagle Ford was a relatively small percentage at about 3%, 4%. And then, of course, other would be the remainder.
Right, understood. And I’m not sure if you all can share this at this time, but could you all maybe directionally point us to kind of where you see the Permian growing as a percentage of total production within the company for full year 2020 that’s kind of embedded in the guidance?
Yes. We have not given that specific guidance yet, Phil, but we certainly expect to continue to see growth out of the Permian and likely double-digit growth into next year, but haven’t given that specifically.
All right, guys. I appreciate the time. That’s it for me.
[Operator Instructions] Next, we have TJ Schultz from RBC Capital Markets.
Some clarification on the distribution for 2020. Is the dollar what you feel gives you plenty of coverage? Or is there any shift in how you handle the payout each quarter to now manage distributions each quarter to keep that 1.2 times, 1.3 times coverage level? Thanks.
I’d answer that this way. I think that as we have done historically, we would probably tend to keep the distribution constant unless there was a meaningful shift away from the benchmark coverage, either positively or negatively throughout the year. But we set the dollar target relative to our budget for distributable cash flow and adjusted EBITDA for the year such that we would have a nice comfortable coverage shield that would make that dollar pretty sustainable throughout the year. And certainly, downside activity could affect it, but I think it’s more likely that it’s got a little bit of upside in it than downside given the hedges.
Okay, great. Thank you.
I don’t have questions at this time. I’d like to turn it over to Mr. Tom Carter.
All right. Well, thanks, everybody, for joining the call today, and we look forward to speaking with you all more in the future. Thanks.
And this concludes today’s conference call. Thank you all for participating. You may now disconnect.