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spk00: Good day, ladies and gentlemen, and welcome to the Blackstone Minerals Third Quarter Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session, and instructions will follow at that time. If anyone should require assistance during the conference, please press star then zero on your touchstone telephone. As a reminder, this conference call is being recorded. I would now like to turn the conference over to your host, Ivan Kiefer, Vice President, Finance and Investor Relations. Thank you. Please go ahead.
spk05: Thank you, and good morning to everyone. Thank you for joining us either by phone or online for the Blackstone Minerals third quarter 2021 earnings conference call. Today's call is being recorded and will be available on our website along with the earnings release, which was issued last night. Before we start, I'd like to advise you that we'll be making forward-looking statements during this call about our plans, expectations, and assumptions regarding future performance. These statements involve risks and may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements. For 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 2020 10-K. We'll refer to certain non-GAAP financial measures that we believe are useful in evaluating our performance. Reconciliation of those metrics 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 from 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, Kerry Clark, Senior Vice President, Land and Legal, and Garrett Grimion, Vice President of Engineering and Geology. I'll now turn the call over to Tom.
spk01: Thanks, Evan. Good morning to everyone on the call. Thank you for joining us today to discuss our third quarter financial and operating results. We had another very solid quarter as prices and production levels exceeded our expectations. The rebound in global demand as COVID cases trend down, combined with an extended period of producer cutbacks and capex and continued capital discipline, have resulted in a big move up in oil and gas prices. In October, oil prices rose above $80 a barrel, levels we have not seen since 2014. Natural gas prices have risen even more dramatically, with Ford prices at their highest level since 2009. To put that in context, I realized price for the third quarter was $38.61 per barrel of oil equivalent, which was more than double the $18.18 per barrel we realized in the third quarter of 2020. The impact of the increase in prices was somewhat muted on our financial results for the quarter since we had hedged approximately 70 percent of our production last year. But we benefit directly on the unhedged 30 percent, and we benefit indirectly in many other ways, like increased producer activity and in discussions around development deals on our acreage. We reported total production of 38 thousand BOE per day for the third quarter of 2021. Of that, royalty volumes increased by 2% from last quarter to 33,000 BOE per day. This increase in royalty volumes was mainly driven from the Midland and Delaware area of the Permian and Louisiana Haynesville properties. Working interest volumes continued to decline and declined by 11% from the last quarter to 5.1,000 BOE. As a result, royalty volumes made up 87% of our total production for the quarter. We had 59 rigs operating across our acreage at the end of the third quarter. That's down slightly from the end of last quarter. But overall operator activity has been on an upward trend since the middle of last year. In fact, that rig count number jumped to 72 as of the end of October. We see the same trend in permitting. We had approximately 400 permits on our acreage in the third quarter, which was roughly in line with what we experienced in the second quarter of this year and well above the approximately 250 permits we saw in the third quarter of last year. Higher prices and royalty production levels contributed to another quarter of strong financial performance. We reported adjusted EBITDA, for the third quarter of 76.5 million, which is 2% below last quarter and 17% above the third quarter of 2020. Distributable cash flow for the third quarter was 70.2 million, which equates to 34 cents per unit. Last week, we announced our distribution for the third quarter of 25 cents per unit. That is equal to the distribution we paid for the second quarter and 25% above our original distribution expectations for the third quarter that we discussed on last quarter's earning call. The 25 cents per unit is 67% higher than our third quarter distribution from last year, and 43% higher than we were paying at the start of this year. Even with the increased payout, we maintained distribution coverage of 1.35 times for the third quarter. Going forward, given our very low debt balances, which is currently below 90 million in total, we will continue to prioritize returning cash flow to our investors. As you've heard from us repeatedly over the last several quarters, the entire team here is focused on exploiting our core acreage positions by continuing to attract new capital to our lands. Blackstone's in a unique position in that we have significant acreage in highly economic plays that remain available for new development. To the extent that we can generate new production volumes and cash flow streams from existing acreage, we equate that to doing an acquisition for $0 of new capital. Two of the areas where we've had success around these organic growth initiatives are in the Shelby Trough and the Austin Chalk. I'll start with an update on the Shelby Trough, which is in the southern extent of the Haynesville and Bossier Play in East Texas. Our acreage in that area is operated by Athon, one of the most experienced producers in the Haynesville. Athon has turned sales to wells under our development program with them in Angelina County. Those wells are performing very nicely and providing some early encouragement that development could involve tighter well spacing than BP envisioned when it was operating in that area. As of October, ATON has spread four additional wells in Angelina County. ATON is also progressing under our development agreement covering San Augustine County, where ATON has spread its first three wells in the area where XTO formerly operated. The Austin chalk trend in Texas continues to garner a lot of attention. SM Energy, EOG, Magnolia, and others are seeing strong well results by redeveloping chalk fields using high intensity completions. We have entered into agreements with multiple operators to drill wells in the Austin Chalk in East Texas, where Blackstone has significant large interest acreage positions. One newer well, in addition to the first new vintage Hancock well, has been drilled and turned to sales, and five additional wells are currently being drilled under these agreements. We are encouraged by the early results, and with the design of the test well program, we will have better visibility across the development area over the next six months as these initial wells come online. We have a lot of positive momentum around the asset base, some of which is driven by improved commodity price in and by an improved commodity price environment, but much of which is a result of hard work by the team here and done during the market downturn. In addition to the Hainesville and Austin chalk, we will be focused on our entire core acreage position, working with industry to move our attractive lands to the top of the industry capital stacks. With that, I'll turn the call over to Jeff.
spk03: Okay, thank you, Tom, and good morning, everyone. It was a really clean quarter, so I'm going to keep my remarks pretty brief so that we can just move on to your questions. As Tom mentioned, we had robust royalty production and an improving commodity price environment. Those things led to another strong quarter of financial performance. Oil benchmark prices averaged over $70 a barrel for the third quarter, and our realized prices before hedges held steady from last quarter at 95% of WTI prices. Gas prices at the Henry Hub averaged over $4 per MMBTU, and our realized price for the quarter, again, before hedges, was 118% of that amount, much of that driven by strong NGL prices. We generated adjusted EBITDA of $76.5 million and distributable cash flow of $70.2 million for the third quarter. Both of those are consistent with second quarter results. That allowed us to stay with our increased distribution level from last quarter of 25 cents per common unit. You may remember from last quarter's discussion that we divided the second quarter distribution into a base distribution level of 20 cents per unit and what we call the special distribution of 5 cents per unit. That was because the second quarter results were positively impacted by a number of one-time items, and we felt at the time that the 20-cent base distribution was more sustainable through the end of the year. Well, we dropped that distinction for the third quarter distribution, as third quarter results were more reflective of our recurring operations, and the better than expected performance fully supported that 25 cents. In fact, even at the 25 cent distribution, as Tom mentioned, we maintained a very healthy distribution coverage of 1.35 times. Our balance sheet remains very strong. We ended the quarter with 99 million of total debt, and a total debt to EBITDA ratio of 0.3 times. As of last Friday, that debt balance was down to $86 million. So the business continues to trend in a positive direction, and we now believe production for the full year of 2021 will be at or near the high end of the revised guidance range of 34.5 to 37,000 BOE per day that we announced just last quarter. Further, we expect lease operating expenses and production costs as a percentage of oil and gas revenues to be at the low end of the revised guidance ranges of 10 to 12 million and 10 to 12% respectively. Finally, we now expect cash and non-cash G&A to be slightly above the revised guidance ranges from last quarter. That's due primarily to the outperformance of 2021 financial and operating results to date relative to our original targets. And with that, Faith, we will open the call for questions.
spk00: Thank you, sir. Ladies and gentlemen, if you have a question at this time, please press the star, then the number one key on your touchstone telephone. If your question has been answered or you wish to remove yourself from the queue, please press the pound key. Your first question is from Stephen Becker of KeyBank. Your line is open.
spk06: Hey, guys. We noticed that your oil production was up 6% to quench in the third quarter. Just want to see what you guys are attributing that to.
spk03: Yeah, I think primarily, and I'll let others chime in, but I think the uptick in oil production is just primarily due to a little outperformance relative to our expectation in the Permian, in the Midland, Delaware basins. Honestly, I think it was as simple as that.
spk06: Got it. Okay. And then I just want to see if there's any more detail you guys can give on the improved well results in the Austin Chalk that you talked about in the release.
spk03: Well, I mean, to be clear, we only have two producing wells in that kind of core area of our Austin Chalk that have utilized the higher intensity completion technology. And That is the Hancock and the Hooper wells. And both of those wells look very, very strong. I'd say just round numbers, two to three times the performance of vintage, less stimulated horizontals in the same area. So that's what we mean by that. I will just note, you know, and we note in the release that we've got another five wells using similar completion technology that will be coming on over the next, several months. We've got three that should turn to sales right around the very end of this year, another in February, and another in March. So we're going to have a number of additional tests that come, but overall, early results are very encouraging.
spk06: Okay, great. Thanks.
spk00: Your next question is from Derek Whitfield from Stifel. Your line is open.
spk04: Good morning, all, and congrats on your quarter and update. Hey, good morning. As a follow-up on the previous question on Q3 oil production, given the strength of your Q3 oil production in general, how should we think about the oil trajectory through year-end based on the Permian and Austin Chalk developments you've noted in your prepared remarks?
spk03: Well, this is Jeff. Derek, I'll start with that, and then others can chime in if they'd like. I mean, as you can tell from our revised guidance, we're still taking a fairly cautious approach to Q4 numbers, so we'll see how that ultimately turns out. And so, again, I think between improved performance in the mid-DEL, I would hope that that continues. I don't think, you know, thinking back around the quarter period, There wasn't an unusual amount of out-of-period activity that affected oil, so I'd say it gives us a more positive orientation around where that may go for the fourth quarter, and that's going to depend, again, well, I'd say Permian was a little above our expectations, and frankly, the Bakken just continues to sort of chug along in a way that surprises us, so We're going to continue to take a relatively cautious outlook on the Bakken. Hopefully the Permian continues. But I think that, you know, from a trend perspective, we hope that it continues to run that way.
spk04: Terrific. And as my follow-up, again, I'll probably get back to the Austin chart just because I'm trying to understand the total update that's been provided to date. When you think about the two wells that have been turned to cells and the five wells that have been spud, could you help us sense what the aerial extent of that activity that's covered by that well, how large of an area is that for you guys?
spk02: So the two wells that have produced thus far are both in Tyler County. It's the Hancock 1H, over 20 months. It produced 3.6. VCF of gas, 531,000 barrels. That is far and above what the offsets produce. The Hooper 1H on a partial month produced two-tenths of a B and 41,000 barrels. So it looks very good relative to the offsets. Again, the older field did not have any stage fracts. So we're certainly hoping that this is a Giddings lookalike. where operators can come in, infill in the main field. We do have an operator who's trying to stretch the field to the north. And what I would say is we're seeing activity in Polk and Tyler counties mainly, but in a very positive comment too, we're seeing a very large public operator, Spud-OL, recently over in Newton County. It's testing another bench within the the play and look forward to seeing results over there. So the field itself, the older field, is spread out over four to five counties, and we're seeing activity within all those areas. And Derek, this is Jeff.
spk03: I'll just add to that. I mean, from an aerial extent perspective, we're talking about well over 200,000 acres of total extent, and we've got additional large acreage blocks that are, you know, following on to those. And so it's a, it's a massive position for us.
spk04: Thanks. Very helpful guys.
spk00: Again, to ask a question, please press the star, then the number one key on your touchstone telephone. Again, that star one on your touchstone telephone.
spk01: Okay. Well, if there aren't any more questions, uh, We thank you for your interest in Blackstone, and we look forward to talking with you next quarter. Thank you much.
spk00: Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.
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