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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Ladies and gentlemen, thank you for standing by, and welcome to the Black Stone Minerals' Fourth Quarter 2020 Earnings Conference Call. [Operator Instructions].
I would now like to hand the conference over to your speaker today, Evan Kiefer, Vice President of Finance and Investor Relations. Thank you, and please go ahead.
Thank you, Samantha. Good morning to everyone, and thank you for joining us either by phone or online for the Black Stone Minerals' Fourth Quarter and Full Year 2020 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 the 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-looking statements in our press release from yesterday and the Risk Factors section in 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 are described in our earnings press release from yesterday, which can be found on our website at blackstoneminerals.com.
Joining me on the call from the company are Tom Carter, Chairman and CEO; Jeff Wood, President and Chief Financial Officer; Steve Putman, Senior Vice President and General Counsel; and Gary Gremillion, Vice President in Engineering of -- in Geology.
And now, I'll turn the call over to Tom.
Thank you, Evan. Good morning, everyone, on the call. Thanks for joining us. We're coming off a difficult week of severe winter storms, and I hope that everybody made it through relatively safely. And their water pipes are getting fixed and they have electricity and all those other things that we take for granted.
I'll begin the call this morning with a quick recap of 2020. The entire oil and gas industry has undergone a period of extreme change in volatility over the past year. While it's not an environment any of us expected or hoped for, we did what was necessary in response to the unprecedented challenges brought about by the pandemic. Our first strategic priority was to further strengthen our liquidity and balance sheet position. We moved very early on in the year with aggressive actions to reduce our costs and reduce our debt.
Over the course of the year, we paid down a total of $273 million of outstanding borrowings under our credit facility, funded by the proceeds from 2 asset sales that we completed in July, and from retained cash flow.
As of December 31, our total debt balance was down to $121 million, and was further reduced to below $100 million prior to paying out our fourth quarter distribution today. As a result, we are in a very strong financial position entering 2021 with liquidity of over $250 million under our current borrowing base. It's important to view this deleveraging in the -- through the lens of the second and third quarters of 2020. The uncertainty around commodity prices and global economic realities was huge, and the goal was to be around for the recovery. Our other major strategic priority which we have discussed on previous earnings calls, was to drive greater activity on our existing acreage.
The acquisition market was slow in 2020 as sellers did not want to part with assets at low prices, buyers were dealing with high cost of capital and limited new capital availability and/or unwillingness to take on additional debt. From a future production standpoint, bringing new capital onto our existing land possession is equivalent to an acquisition that we don't have to pay for. So we focus our efforts on attracting producers to some of our significant acreage positions outside of major shale plays. As we announced earlier in 2020, we struck a deal with Aethon Energy to resume development of our Shelby Trough Haynesville/Bossier acreage in Angelina County after BP exited in 2019.
Aethon has successfully drilled the vertical section of the initial 2 program wells, and has reached total debt on one of these laterals was just in the past week. So far, those wells have been on time and on budget, and we remain optimistic around Aethon's plans and ability to execute in this area. As a reminder, our development program with Aethon calls for 4 wells in the first program year, increasing to 15 wells annually by the third program year, and this is an important factor to recognize as you consider the efforts it takes to spool these plays back up to their peaks of prior years. The other significant piece of our Shelby Trough acreage is just East and San Augustine County, and we continue to make progress attracting capital to that area as well. We entered into an incentive agreement with XTO in 2020 to complete its existing duct inventory in the area. And as of last month, all 13 of those wells have been turned to sales. We are also working with them to reach a mutually beneficial agreement that will help facilitate us bringing another operator into San Augustine.
We hope to have a positive news to report on that front in the near future, and are optimistic about that effort. The other area we feel holds tremendous undeveloped potential is the Austin Chalk play in East Texas. We have seen success with operators using modern fracking completion techniques to significantly improve well performance. We're currently working with existing operators on that acreage to test and develop the area as well as new entrants on unleased acreage. In fact, earlier this month, we entered into an agreement with a large publicly traded operator to drill, test and complete wells in the Austin Chalk formation on some of our East Texas acreage. If successful, the operator has the option to expand this drilling program over significant acreage owned and controlled by us.
Overall, we hold over 200,000 net acres in the East Texas Austin Chalk play that we believe are perspective for enhanced fracking. These acres are in areas that have been productive in prior generations. If results across the acreage deliver a similar uplift to what we've seen in neighboring parts of the Chalk would create a significant new wedge of long-term production and revenue to Blackstone. We are still in the early stages of trying to drive forward these development deals, but they are important in this atmosphere of overall upstream activity. We're working with producers to provide incentives for them to put our acreage at the top of their drilling inventory because producers, in general, are being more selective in where they deploy capital.
We've seen the impact of that across our acreage. As of year-end, there were 38 rigs active on our acreage, and the count has grown to 50 rigs by the end of January. This is above the 29 rigs operating on us at the end of the third quarter, but it's down sharply from activity levels we saw a year ago. It was a similar story in terms of net well adds on our acreage. We added 2 net wells in the fourth quarter, primarily in the Permian and the Haynesville, which was up from the third quarter, but more a full well lower than what we saw in the fourth quarter of '19. We try to base our near-term forecast on activity where we have a line of sight. Jeff will go into more detail about our '21 guidance, but we have fully incorporated the lower level of current rig activity into that guidance. And hope that will prove to be conservative as things continue to recover. To be specific, our long-term thesis is to maximize royalty production in a responsible way to create distribution growth for our unitholders.
And in fact, we were able to announce an increase in our distribution this year. We have maintained a substantial coverage ratio to our distribution over the past year as we diverted retained cash flow towards debt repayment. With our significant progress on that front, the Board felt it comfortable to pay out a higher percentage of our free cash flow. So one of the great results of our balance sheet efforts is the ability to return more cash to our unitholders. We set the annualized run rate distribution of $0.70 per unit at a level we believe is sustainable throughout 2021. We look forward to updating you on our strategic initiatives throughout the year. With that, I'm going to turn the call over to Jeff.
All right. Well, thank you, Tom, and good morning to everyone. Results for the fourth quarter of 2020 came in a bit above our expectations, that was driven by outperformance in the Louisiana Haynesville and the Bakken/Three Forks. We generated 32,000 BOE per day of mineral and royalty production in the fourth quarter, and that was a 3% increase from last quarter. And we had 39,000 BOE per day in total production volumes, that's also up 3% from the third quarter. Total production for the full year was 41.6 MBOE per day, which was at the upper end of our revised guidance range.
Realized prices for oil and gas continued to improve in the fourth quarter. You'll remember, we had unusually wide oil differentials in the third quarter, and those normalized this quarter to result in an average realized oil price of $40.20 per barrel. Gas differentials also benefited from improving NGL prices during the quarter, resulting in our realized gas price averaging $2.68 per MMBTU that was slightly higher than the average Henry Hub price.
Even with the improving price environment, our hedge portfolio generated $14.6 million in cash settlements to our favor during the fourth quarter. Expenses came in a little better than our expectations with LOE and production costs below our guidance levels. Tom mentioned the efforts that we took in the beginning of 2020 to lower our G&A expenses. Total G&A costs were $10.2 million for the quarter and were $43 million for the full year, that number is a decrease of 32% over our 2019 G&A levels.
We reported $72.3 million of adjusted EBITDA and $65.9 million of distributable cash flow for the fourth quarter. Both of those metrics were up over 10% relative to the third quarter. Even with the distribution increase to $0.175 per unit, or $0.70 per unit annualized, we generated distribution coverage of 1.8x, which allowed us to repay $26 million of debt during the fourth quarter. As part of our release yesterday afternoon, we gave guidance for 2021.
As Tom said, we based this guidance on producer feedback, known permits and 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. And in areas like the Chalk, we only include limited contributions from producers with clear drilling plans. Our royalty volume estimate represents a 13% decline from 2020 volumes, that's reflecting declines in our relatively mature Bakken and Eagle Ford positions, a full year impact of the Permian asset sales and a lower level of drilling activity outside the major shale plays. We also expect our Shelby Trough production to trend lower in '21 from existing PDP declines before the expected ramp-up in activity from our new development deals. Adding to that, some existing Shelby Trough wells took frac hits, and will require some work over activity before returning to previous production levels, and that also negatively impacts our '21 forecast. We expect working interest volumes to decline by about 25%. That, of course, is by design as we intentionally stopped investing in that part of the business in 2017.
And as a result, we expect royalty volumes to increase to about 83% of total production volumes in 2021. We're estimating lease bonus for the year of around $10 million, that reflects overall leasing activity that's consistent with 2020 levels and also reflects our decision to forgo lease bonus in certain situations in favor of more robust drilling commitments from our operators.
We expect lease operating expenses and production costs to be in line with 2020 levels. We also expect total G&A expenses to be comparable to the reduced levels of 2020, but to be composed of lower cash G&A costs and slightly higher noncash costs.
This outlook for '21 supports the $0.70 per unit distribution run rate beginning with the fourth quarter distribution being paid today. We anticipate the distribution coverage will come down a bit, over the course of, the year due to the lower production volumes and lower realized oil prices after taking into account our hedge portfolio.
But as Tom said, one of the benefits of having such a clean balance sheet is the ability to increase our payout ratio and return more of our cash to our unitholders. As Tom mentioned in his opening remarks, we're coming off a very challenging week here in Texas, and we hope all of you in the area made it through intact.
And with that, Samantha, we will open it up for questions.
[Operator Instructions]. Your first question comes from the line of Brian Downey.
Question on the guidance. I'm curious, first, how you see the production trajectory during the year, particularly on the gas side with the recent DUC completions and the Shelby Trough's development agreement, as you alluded to those volumes rebounding. How should we think about the cadence of those rebounding volumes versus PDP declines as we go through '21?
Yes. Brian, this is Jeff. Thanks for the question. And I think you, quite frankly, sort of answered it. I mean we would expect that, over the course of the year, primarily driven by gas volumes that those would trend down. And for -- really for the factors that you cited there, right? We had a pretty good uptick in volumes from the XTO DUCs, all 13 of those that got completed by the end of January. So we're seeing the volume impact of those early in the year, and those will trend down. And again, I think that will trend down in advance of the new levels of activity coming in that Shelby Trough area from Aethon and hopefully others, but yes, I would call it just sort of a general decline, primarily led by gas through the course of the year.
I'll just add to that. When you think about 2021 in the context of 2020 and 2019 and 2018 and going forward, you have to understand that we've brought in a whole new set of capital providers out there, and they are ramping those programs back up. And they were at very high levels before BP left the area and XTO slowed down. And it does take time for those things to school back up, but we are very happy with what's happening there and 2021 will be a transition year from the prior tenants, if you will, to activity by the new tenants.
And I guess just to clarify, how should we think about first quarter volumes relative to sort of where 4Q volumes were? I know there's some understandably some weather noise there as well, but is that the full effect of those DUCs? Is that more early 2021?
You want to take it?
Yes. So this is Evan. Thinking kind of around where Q1 is, really kind of our start rate is where we've been kind of guiding everyone kind of around Q4 and kind of assuming that we're going to see kind of that mid-30 production level starting off.
Got it. And then I guess on my follow-up question, on the leasing and development agreement side, you clearly had some nice successes. In the Shelby Trough on the gas side in 2020, you mentioned that the East Texas, Austin Chalk in your remarks. As the commodity macro outlook has improved, are there any other areas where early discussions we could hear of maybe some incremental leasing or development agreements as we go through this year?
Well, this is Jeff. I mean I would say we're pushing on every front we can, given the improving commodity price environment. Obviously, some of those early deals that we struck in '20 were in just completely different overall look on -- especially outlook on gas. So I'd say we're focused on the San Augustine side of the Shelby Trough. There are numerous areas across the Austin Chalk that we're working just given the size of our acreage position there. And then, look, there's others Wilcox...
The Louisiana and Haynesville.
The Louisiana, Haynesville that we're doing everything we can to try to move up and operator's capital stack as we go through. And it's not just in Texas, as Gary just mentioned. We did have success with a major operator on the Louisiana, Haynesville side in structuring an incentive deal that brought capital onto the Louisiana acreage. And as I mentioned in my prepared remarks, that's one of the areas that sort of outperformed in the fourth quarter. So we would hope to continue to see those opportunities, and they should be a little easier to come by in a more constructive gas environment.
And keep in mind, when we're talking about East Texas versus some of the other Bakken and Permian, when those are areas of very high acreage concentrations for us with substantial ownership as opposed to lower nets in some of the other plays. And we have so much acreage there that those are highly impactful as they develop for us. And we're going to be working those very hard.
Your next question comes from the line of Derrick Whitfield with Stifel.
Congrats on the Austin Chalk agreement. Regarding your 2021 guidance, could you offer any color on line-of-sight activity, including net permits and net DUCs? And then also speak to the degree of weather impacts and frac hits factored into your guidance? Clearly, the last part, more specific to Q1, just to clarify.
Yes. I may let Evan take a shot at your first one. I mean, we did -- so as XTO was completing those 13 wells, there were just some existing PDP that had some frac hits. And we think probably, overall, that's in the range of 700 to 800 BOE a day off of '21 production guidance in total, and that would be sort of front-loaded in the early part of the year. In terms of permitting and rig activity and those other things that tend to drive our forecast, we have seen those step-up. I think Tom mentioned this in some of his opening remarks. I mean, we had 38 rigs on us at the end of the year, that had moved up to 50 by the end of January. And while that's a big improvement from what we saw in the second and third quarters, it's still sort of half of where we were a year ago. And it was a similar story in terms of permits, where the trend is definitely moving in the right direction, but it's quite a bit lower. Evan, I don't know if there's other color you'd want to give. But I mean, that's the kind of stuff that we tend to look at on a play-by-play basis to drive the forecast.
Yes. And that's exactly correct. So we'll go and look at any existing permits on our acreage. And whenever we're saying, line of sight, we typically just rely on the data that we have a good visibility on. So we're not factoring any future permits that will be permitted throughout the year unless the operator has told us otherwise. So we're focused purely on what we currently see out there, and that's what we're expecting to be drilled throughout the year. And then kind of your other comment as far as the weather, we're still kind of working through trying to figure out what the overall impact is. Obviously, we've seen the impact in the Permian from what we've seen out there as well as kind of any other areas that could see any of these freeze over. So we're trying to kind of work through and see what the overall impact of that could be.
That makes sense. And with my follow-up, I wanted to drill down on your comments regarding you guys working with XTO on a mutually beneficial agreement that will help. You guys attract another operator to develop the San Augustine acreage. Could you offer any color on how that might take shape and the degree of interest you're seeing in this area?
Yes. Well, look, we've got interest in the area, right? The issue is, I think, that XTO, Exxon, at the moment, just has: a, a lot on their plate; and b, maybe other areas that they're focused on. So we jointly own sort of that core piece in San Augustine County that we call the Brent Miller area. So to the extent that we can just work something out where they can develop a piece on their own time line and maybe we could get a piece out to a different operator that may want to do something on a little more aggressive time line, but hopefully, that would work with both. But I think it'd be tough to say anything more right now just given we're in discussions with those guys about working something that hopefully benefits both of us.
I would add, when Jeff says, we are joint owners with them out there. Just to clarify because of the question. We -- he's talking about from a working interest standpoint because we own the minerals under a lot of that acreage as do they. But we're talking about the working interest side, and that's an outgrowth of the evolution of that play. And we had a working interest out there, which we had farmed out. But what we are doing is looking to take our working interest on specific areas and bring another operator in there. So -- and actually double down on who's developing out there. But beyond that, we hope to be able to say more later.
And Derrick, that's just one area that we share the working interest with XTO. We've got a ton of additional open acreage in San Augustine. So the idea is just can we put together a larger program to attract somebody in there.
And underscore, we're not saying that we're going to start taking working interest, we are internally with our own capital, but it does give us the ability to bring a partner in to work on the area.
Your next question comes from the line of Pearce Hammond with Simmons Energy.
Jeff, I wanted to start off, just want to get your thoughts on gas hedging. Do you prefer to keep a certain hedge percentage in front of you for the next 12 months? Just want to understand how you're thinking about that right now?
Yes. We just -- we have historically just tried to be pretty programmatic about that, Pearce. So we don't -- I mean, I guess every time you choose to put a hedge on one day versus another, you're making a mini call on price, but we try to just do it systematically. And so what I would expect is in keeping with prior years that we would look to in pretty short order, start to establish some '22 hedge positions on both oil and gas and then just ramp those up, over the course of the year, to where as we're coming into '22 that we would be in that traditional kind of 70, 80-plus percent hedged range.
Okay. Perfect. And then my follow-up, I'm just curious if you could provide some more color on the Austin Chalk. Congrats on that agreement. And what does the producer see there? Is it really good gassy wells? What are these fairly deep wells, expensive wells? Just curious what the Austin Chalk looks like for you? And what the producer is seeing?
Pearce, this is Garrett. So it's a pretty good combination of condensate and gas. The older wells in the area were completely unstimulated. We've recently had some good data points on multi-stage frac wells. And what we're seeing on the first well that was very successful, is over 300 producing days, well made 300,000 barrels and 2 BCF compared to the direct offset, which was unstimulated at about 50,000 barrels and 1 BCF. So we're kind of hoping we have a getting field redevelopment look-alike area over here. And we're certainly pushing to try to get future development and some more new wells this year.
[Operator Instructions]. Our next question comes from the line of Leo Mariani with KeyBanc.
Just wanted to get a sense and a little bit more color potentially on your '21 guidance. You've made some comments about it already, but I just wanted to be clarified. I mean it sounds like you're kind of assuming 2020 levels in the Permian. I think that was one of your comments. And then just additionally, you had some Haynesville activity at the start of the year, but it sounds like you're expecting that to trail off quite a bit as we get into 2Q '21 and 3Q '21. Just wanted to kind of verify that's what you guys are sort of framing up? And is there any way to roughly quantify maybe the number of net kind of Haynesville turn-in-lines you would expect here in '21?
Yes. So the way we're looking at the gas production is that you're right that we have the 13 DUCs that were completed here in January, that is offset a little bit by several wells that were, take it offline just for workovers due to frac hits. But then kind of continuing that activity out in the Shelby Trough, that's going to be the Aethon wells. They've already drilled the first 2 through the vertical sections. They're currently in the horizontal. And whenever those come online later in the year, that's where we're going to start to see a little bit more of a kind of the ramp-up in those volumes, but that's going to be later in the year. So we are seeing a decline in the gas volumes throughout the year and then kind of holding steady towards the end. Beyond that, there is some agreements that we've done out in Louisiana side that's going to help bolster some of that production going forward as well.
Okay. Great. And just also wanted to ask a kind of a bit of a strategic question for you folks here. You obviously have done a great job in kind of cleaning up the balance sheet to a point where your leverage is pretty de minimis at the end of the day here. We're clearly in a slightly different A&D market than we were a couple of months ago, certainly, it looks like things have kind of loosened up and deals are starting to happen. What's the appetite at Black Stone to potentially get a little bit more active there? I know there's a big push to get people to lease existing minerals, but is there also kind of a second component here? You guys may try to get a little bit more active now that things are maybe more open in '21?
Leo, I'll start. This is Jeff. Sure. I think the appetite is always there. It's really just been a function of the market. I think what we saw in late '19 and all of '20 is that the sellers, many of whom had acquired their assets in a different commodity environment and more active M&A environment, more expensive M&A environment, frankly. We're not looking to part with those assets in a cheaper, less expensive, less active M&A environment. And so you just -- you had a bit of a mismatch between sellers and buyers who had had their cost of capital beat up pretty hard.
And I think we're seeing that continue a bit. I mean, now that prices have rebounded pretty significantly, we've seen prices move a lot. We've seen our equity values recover somewhat. So I still think there's a bit of a disconnect probably between what a seller is going to want to see and what at least the public buyer is willing and able to pay given access to capital. So in short, I think the appetite is there, but that deal is going to have to make sense for us on a long term, both accretion and both distribution and NAV accretion basis. So if we can find those deals, we would love to do them. And we'll be looking. But in the meantime, any time that we can get new streams of cash flows out of our existing assets, that's just a huge win for us and our unitholders.
Your next question comes from the line of Harry Halbach with Raymond James.
Congratulations on your enhanced shareholder return policies. In regards to the $75 million buyback program, I was kind of wondering, what is your philosophy around implementing that? Is there a certain next 12-month equity yield being targeted? Or just kind of tell me how you all are thinking about that?
Yes. I think that's just -- that's there for us to be opportunistic. I think the focus is more to -- now that the balance sheet is really pretty bulletproof to -- the focus is really to put as much cash as we can into our unitholders' pockets. And that probably takes priority over share repurchases in the near term. Now if there's another giant dislocation in the market, and it looks even more compelling, then we're going to revisit that. But I think in the near term, again, the focus is going to be, can we increase that payout ratio and put more money in our shareholders' hands.
And then just a quick another question. What is your federal acreage exposure across your portfolio and in the Permian specifically? I know your Permian position is heavily weighted towards Texas, so I wouldn't think it would be much, but just wanted some additional detail.
Yes.
This is Jeff. I'll start, and others may want to check-in. Look, we definitely have areas where there's federal exposure. So the balance of this whole Biden administration is probably as one of the larger owners of minerals on private lands, restrictions on public moves more activity to us. So that's a net positive. The negative that are areas where we have acreage, where there's also federal ownership, which could make things more difficult. We don't, for example, in the Permian, New Mexico is not a big position for us, which is more federally owned than the Texas side. So overall, we don't think -- I mean, in going through the '21 guidance and the longer forecast internally. We don't think that, that's a huge impediment to Black Stone and maybe a bit of a push from the positives of driving more capital on a private acreage, which were obviously a huge owner.
We have reached our allotted time for questions and answers. I would like to turn the call back over to management for any additional or closing remarks.
Well, great to speak with you all today. It's been a long year. It's been a long week. The sky is blue today. It's 70 degrees in Houston. We're looking forward to a great year, and we hope you all have won yourselves. We'll talk to you next quarter.
Ladies and gentlemen, this does conclude today's conference call. You may now disconnect your lines.