Good day, and thank you for standing by. Welcome to the Black Stone Minerals fourth quarter earnings conference call. At this time, all participants are in a listen-only mode. After the speakers' presentations, there will be a question-and-answer session. To ask a question during that session, you'll need to press star one on your telephone. Be advised that today's conference is being recorded, and if you require any assistance during the call, please press star zero. I would now like to hand the conference over to your speaker today, Mr. Evan Kiefer, Vice President of Investor Relations. Mr. Kiefer, the floor is yours. Thank you, Chris. 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 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, we'd like to advise you that we'll 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-looking statements in our press release from yesterday and the Risk Factors sections from our 2021 10-K, which we expect to file later today. You may refer to certain non-GAAP financial measures that we believe are useful in evaluating our performance. A reconciliation of those metrics or 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, Carrie Clark, Senior Vice President of Land and Legal, Garrett Gremillion, Vice President of Engineering and Geology, and Thad Montgomery, Director of Land. I'll now turn the call over to Tom. Thank you, Evan. Good morning to everyone on the call, and thanks for joining us today to discuss our fourth quarter and full year 2021 financial and operating results. We posted another solid quarter and are entering 2022 with good momentum across our business. Oil and gas prices continued to strengthen in the fourth quarter. That's a trend we benefited from through 2021. Realized prices in the fourth quarter were just over $73 per barrel of oil and $5.40 per Mcf of gas. On a BOE basis, prices were up 14% from the third quarter and doubled from the levels we saw in the fourth quarter of 2020. Not surprisingly, the more constructive commodity price environment has been positive for overall activity and volume trends as well. We had 95 rigs operating on our acreage at the end of the year, which is up over 60% from the 59 rigs operating at the end of the third quarter, and it's more than double the 38 rigs we saw at the end of 2020. Our royalty volumes in the fourth quarter totaled 35.2 MBOE per day, which is up by 7% over the third quarter royalty volumes, driven by increases in our Bakken, Louisiana Haynesville, and Midland-Delaware production. Our working interest volumes continued to trend down in the fourth quarter as our legacy working interest production rolls off from the Shelby Trough wells, where we participated prior to our farm- outs of that interest in 2017. As a result, royalty volumes now represent 90% of our total production volumes. While royalty volumes trended up throughout the year, the average volumes for 2021 were relatively flat to 2020 royalty production levels. As those of you who have been with us for a while know well, our overall volume growth has been slowed over the past couple of years due to declining natural gas production in our concentrated acreage position in the Shelby Trough Haynesville Bossier play in East Texas. After maintaining very active drilling programs in the area, XTO and BP shut down their Shelby Trough programs in 2019, and in doing so, released their rights to much of the acreage. We made it a top priority to bring in a new operator in the area, and in 2020 and 2021, we did that through two separate development deals with Aethon Energy. Aethon continues to ramp up its activity in the Shelby Trough. In Angelina County, Texas, two wells are currently producing under our agreement with Aethon, and another eight wells are being drilled or completed. In San Augustine County, Aethon is currently drilling three wells under a separate development agreement covering that area. We have also renewed existing and added new farm-out agreements covering the area to relieve Black Stone of any direct capital burdens of working interest. Our overall activity levels with Aethon across the Shelby Trough are expected to increase quickly over the next two years, leading to what may be 20-30 wells a year from that area. That will add to our total Haynesville volumes from East Texas and Louisiana over the coming years. Haynesville has always been an important contributor to our total production mix, and we believe that the play is uniquely well-positioned to benefit from continued growth in LNG export volumes. That program is up and running with a very experienced and well-capitalized operator. We're working to repeat that success in other areas where we have significant mineral and royalty positions, either by attracting capital to unleased acreage or working with existing operators to accelerate drilling activity on the acreage. We have prioritized this organic growth strategy for some time now and have added horsepower through our new hires to our team focused on this effort. Clearly, volumes from new drilling activity on existing acreage provide a higher return to our shareholders than adding volume through acquisitions. We think the organic focus is particularly appropriate in the current high commodity price environment, which enhances the economics when we are showing acreage packages to potential operating partners. In our view, creates more downside risk when paying for acquisitions. Our extensive footprint in the Austin Chalk is an important component of our growth efforts. As you probably know, from previous calls, we've been working with existing operators in marketing unleased acreage packages in the area. We continue to make progress on these efforts and are seeing some encouraging results in the initial deals struck last year. Thus far, five wells have been drilled and turned to sales, and another two wells are in various stages of drilling or completion under these agreements. Not surprisingly, we've seen some variability across such a large acreage position. In general, we remain very optimistic that there's a sizable fairway or fairways ripe for development using the latest generation of high-intensity completions. Of course, we're not stopping with the Shelby Trough or Austin Chalk. We're currently actively looking into other parts of our mineral portfolio that could benefit from this combination of constructive commodity prices and improved technology, and where new development can drive further volume growth. We're optimistic about the years ahead. We have a strong balance sheet, a robust portfolio of growth opportunities, and a great team focused on turning these opportunities into additional volumes, all with the goal of returning more cash to our shareholders. With that, I'll turn the call over to Jeff to go through some of the details of the quarter and our outlook for next year. Okay. Thank you, and good morning, everyone. As Tom mentioned, we had another good quarter and ended the year on a high note in terms of both royalty and total production. Royalty production was up 7% from last quarter. Those production gains primarily occurred in our Bakken, Permian, and Louisiana Haynesville acreage. The further good news is that the increase was driven primarily by higher oil volumes, which were up 14% from third quarter levels. A lot of good things happen when new well activity picks up. We benefit from the relatively high production rates in the first month of a well, and since most times we receive an initial check for a well several months after that well actually began producing, we may book several months of historical revenue and production at the same time when we get that first check. That, of course, occurs more often in times of increasing activity, which is what we saw in the fourth quarter, and specifically, what we saw in the Bakken and Permian, which drove up our oil volumes. Prices continued to climb in the fourth quarter, boosting our oil and gas revenues to over $150 million for the quarter. Our oil differentials remained steady at about 95% of WTI, but we saw a big divergence in gas prices between the average spot price and the average Henry Hub contract settlement price for the quarter. Normally, those two metrics track very closely. In the fourth quarter, the average spot price was $4.75, compared to the average settlement price of $5.83. A portion of our gas production are priced off of each of these, and as a result, our realized gas price of $5.40 was 114% of the daily spot average. That's pretty consistent with what we've seen in prior quarters, but was just 93% of the contract settlement price average. We recorded adjusted EBITDA of $77.6 million for the fourth quarter. That was up slightly from last quarter. Distributable cash flow for the quarter was $71.3 million, also up from last quarter. On the back of those results and the positive momentum going into 2022 that Tom mentioned, we were able to raise our distribution again to $0.27 per common unit. That's an 8% increase from last quarter. Even with that increase, our distribution coverage for the quarter was 1.3 x, and we retained about $15 million of cash. For the full year, we generated $292 million of adjusted EBITDA from 38,000 BOE per day of total production. Distributions paid for the full year totaled $0.945 per unit, and we retained about $70 million for acquisitions and debt repayment. In conjunction with the earnings release, we put out our 2022 guidance yesterday. As we look forward to the full year of 2022, we forecast royalty production to be relatively flat to 2021 levels. We expect to see continued production gains in the Permian and Louisiana Haynesville plays, offset by the natural production declines in the legacy XTO and BP Shelby Trough wells that Tom discussed. Given the expected ramp-up in drilling there by Aethon, we expect our Shelby Trough production to return to a growth path later this year. Working interest volumes will continue to decline into 2022, given the existing farm-out programs we have in place, including the one with Azul Resources, who has joined in the San Augustine Shelby Trough program as a new farm-out partner. We expect lease bonus, operating expense, and production costs to be roughly in line with 2021 levels. G&A is expected to increase slightly due to just normal cost inflation and some selective hires we've made to drive our organic growth initiatives forward. While we don't normally give distribution guidance, I will note that cash flows will benefit in 2022 from the step-up in our average hedged prices. The fixed prices on our oil hedges move up by about 70% from 2021 levels, and the hedged gas prices increased by about 16%. As a final point, our balance sheet remains in great shape, and we have ample liquidity. We ended the year with $89 million drawn under our revolver, which has a $400 million borrowing base. As of Friday, that debt balance was down to $58 million in advance of paying the distribution, which happens tomorrow. With that, Chris, we will open the call up for questions. Thank you, sir. As a reminder, to ask a question, you'll need to press star one on your telephone. To withdraw your question, please press pound key. Stand by as we compile the Q&A roster. Our first question comes from Leo Mariani of KeyBanc Capital Markets. Your line is open. Hey, good morning, guys. A couple quick questions here for you. You clearly mentioned that you saw a really nice benefit in the fourth quarter due to, I guess, what appear to be sort of, you know, prior period adjustments. I know there's time lags between when you get the checks, you know, for the production when you actually have to book these, you know, volumes here. So could y'all quantify that here in the fourth quarter in terms of, you know, was it 1,000 barrels a day or just anything like that you could say in terms of kinda what was more prior period volumes versus kinda what the actual maybe run rate volumes were for the quarter here? Hey, Leo. Good morning, and sure, happy to do that. This is Jeff. So yeah, I mean, I think just to clarify your point for everyone on the call, I know we mentioned it a bit in the prepared remarks, but you know, we get new wells added across the system all the time. Typically, that operator, you know, may take a few months before we get that first check. When a new well comes on that we had not seen before and therefore hadn't accrued into our financials, then let's say we got that check in December and production actually came on in September. Well, not only are we booking the September production that we saw on that check, but we're gonna establish a new accrual for the September through December volumes for that specific well as well. It can just provide a lot of positive momentum to our overall volumes quarter-over-quarter. As I mentioned, that happens with greater frequency as activity levels overall are picking up. We saw about 4,000 BOE a day that we were impacted through new well activity in the fourth quarter. That would show. Yeah. Okay. Yeah, that's very helpful. Obviously, you guys significantly kinda outperformed your guidance in 2021, which y'all had actually raised, you know, as well, earlier in the year. That certainly is good to see. When I look at kind of momentum, you know, right now, you know, the 95 rigs, just like you said, up 61% versus last quarter, I mean, it certainly probably doesn't appear to be slowing down at current commodity prices. When you look at your guidance for 2022, I don't wanna put words in your mouth, but I'm assuming that, you know, perhaps you're not necessarily, you know, assuming some of these same benefits of flush production on the bigger wells. Maybe it's more of kind of a base production rate. It seems like with such high activity, you could see something similar in 2022, which is, you know, getting some of these, you know, extra checks on flush production, some of the wells which could make the volumes look a little better. Is that kind of maybe a way to think about it in 2022? Well, Leo, yeah. Let me clarify. You know, the reason why we might have pretty sizable adjustments related to some of that first check issues is because we only accrue what we can see, right? We can't make accruals for wells that we don't know about. Obviously, with, you know, 65,000-70,000 wells across the system and new ones added all the time, we don't have direct visibility into those. We don't get daily production estimates, for example, from producers. We do our best to accrue volumes. That's in the actual financials. When we forecast, that's a little different than what we actually accrue for GAAP purposes. We try to take into account increasing activity when we forecast. Now, if you look historically, at least in normal periods of activity, we've tended to be a little conservative in our forecast. I think that does come from just not being able to have great visibility into all that new activity. But it's not quite the same thing as when we're adjusting those accruals for new well activity. What I will say, and I know we've said this for a number of years, but it's really important. You do have to remember that Shelby Trough production, as we got into 2019, was about 1/3 of our total production base in this company. When BP and XTO stopped, that was, you know, a pretty big spinning wheel that stopped spinning. Those wells, because they're choked back and they're massive wells, hang on for 12 or 18 months, and then you really start to see the meat of the decline curve in those Shelby Trough wells. That's what we saw in 2021, and we think we're still seeing in 2022. The good news is that with all the activity that Aethon has going on out there, we do expect 2022 to be the year where, you know, we start to fully offset that decline in the Shelby Trough volumes. I mean, that's gonna be, in our forecast, that's 2+ a day that we view as volume decline just from the Shelby Trough, from those legacy wells from 2021 to 2022. That colors that forecast a little bit. Obviously in a lot of the other areas, Perm, and even Bakken, Louisiana Haynesville, you know, we expect to see that continued activity level result in higher volumes coming out of those plays. Okay. That's very helpful in terms of describing that dynamic and the guidance for 2022. Maybe just last one for you guys here on just M&A. It sounds like maybe y'all are being a little bit more cautious given that we're in a higher price environment, and it seemed like the strong preference there internally is to still just try to get a lot of this unleased acreage out there in the portfolio. Maybe just give your thoughts overall on the M&A environment. Yeah. This is Jeff. I'll start, and anyone else can chime in here around our table. Look, I think you basically just summed up our current thinking very well, right? We see a lot of opportunity across the portfolio. We've had success now two times around with the Shelby Trough acreage in East Texas. We're really starting to see some momentum, and we're excited about what's going on in the Austin Chalk. Frankly, there's just a lot of areas where we have concentrated acreage positions that we think, you know, can really benefit from completion technology and can really obviously the economics look pretty good in this sort of pricing environment. We're really focusing our efforts and why we brought Carrie on and have added on to her team and that's really her focus. I will tell you, Tom's as invigorated about this as I've seen in a long time. There's just a lot of opportunities around the portfolio. To the extent that we can start adding cash flow streams through bringing people onto our existing acreage, we've said this time and time again, that's like doing an acquisition we don't have to pay for. When you think about IRRs and how you generate long-term returns for our shareholders, we think that that's just a very productive way to do it. We're fortunate enough to have large, contiguous, high net positions where you're relevant to the producers that you're talking to in those discussions. A lot of stars have to line up for that stuff to work, and a lot of hard work has to go into it, but that's where we're focused. We will get back to acquisitions someday, but we think, frankly, this is the time better spent on chasing those organic deals at the moment. Okay, great. Makes a lot of sense. Thank you. Thank you, Leo. Thank you. Our next question comes from Derrick Whitfield of Stifel. Your line is open. Good morning, all, and congrats on your quarter end update. Hey, Derrick. Regarding the Austin Chalk, you noted in your prepared remarks that the wells are showing some variability and significantly improved well performance relative to prior generation completions. Could you perhaps speak to the nature of the variability you're seeing, and if it's productivity or production mix related? Yeah, Derrick, this is Tom. I'll speak to it a little bit. You know, the Austin Chalk play has gone through at least four or five different renaissance cycles over the last several decades, and it is one that is known for a lot of variability. We are working on our portfolio with operators in areas that have been very active and very productive and very economic in the past with a lot of wells, hundreds of HBP units that were pretty darn good wells in the last generation without any fracture stimulation in those wells. In addition to that, operators and people want to look in areas that haven't been successful, as successful in the past, and that's generally rock quality and other things like that, trying to put new technology to work out there and see if that works. The variability so far has been more around the areas that didn't work before have not worked as well with the new stimulation. However, it's early innings, but the volume of control is building up rapidly. In the areas where the wells were pretty good before, and it's a massive fairway, the wells that have been drilled in those areas, in the areas that were good before and fracture stimulated look tremendous. There's a ton of inventory just in that area, but we expect to keep working on other areas as well. The variability hasn't been. The areas that were good before, they look pretty darn exciting. It's challenging, and we will continue to do it to expand those areas into areas that haven't worked before. That makes sense, and it's quite encouraging that you guys are being able, at this early point, to map that out. Congrats to you guys on that. Then maybe shifting over to the Haynesville with my follow-up. Could you speak to the importance of your agreement or farm-out agreement with Aethon and your expectation for activity under this agreement? Then perhaps more broadly on Shelby Trough development, could you speak to your timing expectations for the eight wells that are being drilled? Completed in Angelina County? Hey, Derrick, this is Jeff. I'll start. Just, you know, the Aethon agreement is just bringing in a new partner, which has resulted in, you know, the full breadth of our working interest there farmed out. It's a new entity backed by Carnelian, good group of guys, well-capitalized, and we're great. We're happy to have those guys in the fold. But again, all of these farm-outs that are in place, and we now have three farm-out partners, are just there to make sure that a very active well program under Aethon in the Shelby Trough continues to be appropriately capitalized and frankly not capitalized by us 'cause we're out of the working interest business. That's just adding another strong partner to that end. In terms of the Aethon development, I mean, obviously that's an incredibly important program. What we're seeing is that they were required to drill under that agreement a minimum of five wells in the first program year in San Augustine. I think they're going to exceed that and probably hit eight. And that eight ramps up to 10 and then eventually to 12. On the Angelina side, within the next couple of years, that program is supposed to ramp up to 15 wells per year. In terms of specific timing on those, they're just keeping track with those program years, and in fact, exceeding our expectations a little bit. That's what's kind of got us excited by the, you know, within a couple of years, the program envisions a minimum of 27 wells per year being drilled across Angelina and San Augustine, so in just the Shelby Trough. I think it just highlights why we're so happy that this is Aethon, given they're one of the most prolific Haynesville drillers, seeing, you know, their technical wherewithal, we think is very, very strong, and these are steep and high-pressured wells, so you want the right people drilling them. Yeah, I think it's gonna be a very important relationship going forward, and so far, you know, they've been terrific to work with. Thanks, Jeff. That makes sense, and it's very helpful. Thanks, Derrick. Thank you. To ask a question, please press star one on your telephone. To withdraw your question, please press the pound key. Our next question comes from Joseph McKay of Wells Fargo. Your line is open. Hey, good morning, guys. Congrats on a great quarter. Just had a little question on the 2022 guidance. In terms of the natural gas cut, the 72% compared to the 74% and kind of 75% level you came at, in 2021. Could you just talk about kind of what's driving that and I guess the trajectory of that? Is that kind of a step down we expect to see in 1Q and then hold steady throughout the year? Or is that something that, you know, you expect to kind of exit the year maybe closer to 70%? Just a little more color around that if you can. Yeah. Sure, Joseph. Thanks for the question. This is Jeff, and then I'm gonna let Evan answer the second part of your question. I think the general step down in gas from 74%-72%, and obviously the corresponding step up in oil is just. I know all of our answers tend to circle back to this, but a lot of that is just, you know, the Shelby Trough is 100% dry gas. This kind of last year of, hopefully, step down in production volumes in the Shelby Trough is almost completely from gas. What we're seeing, frankly, a little surprisingly, is areas like the Bakken, where we're forecasting it to be flat to slightly up, whereas a year ago, we would have expected that to be a declining asset. We've seen more new drilling activity come with higher oil prices. Of course, we think that the Mid-Del is gonna continue to grow. That transition a little bit in terms of product mix is really driven by that combination. Shelby Trough continuing to trend down relative to 2021 prior to when we think it's gonna, you know, bottom out and start a growth trajectory again, and then just continuing to be optimistic around some of the oilier plays like the Permian and the Bakken. I'll let Evan kind of address the mix throughout the year. Yeah. Thanks. This is Evan, talking about just production and kind of mix throughout the year. Overall, we see a little bit of a step down starting in Q1. Thinking just oil first, you know, given where we see rig counts and overall activity, we do expect a slight increase in oil volumes kind of throughout the year. Kind of discussing on the gas side, it really is a Shelby Trough story. We've got early in the year as the decline in those assets and as the additional wells come online that Aethon is currently drilling, we see that kind of inflection point more towards the middle and second half of the year as we start to see those growing. It is an initial step down and then kind of slight increase overall throughout the year, really kind of driving more towards the second half of the year with gas volume growth. Gotcha. Thank you. That's helpful. I wanted to touch on one of the comments around G&A for 2022 in terms of marketing undeveloped acreage. Are there any plans beyond kind of the normal course of business stuff? Or, you know, if there are larger kind of divestiture plans, how are you thinking about use of proceeds, just given the balance sheet's in great shape? Maybe just kind of following on that, how are you thinking about the payout ratio as you guys move throughout 2022? Yeah, Joseph, there's no divestiture plans. I mean, just because we're being even more selective than we historically have on the acquisition front, doesn't mean we're in the market to divest any of these assets. What we wanna do is take the assets and just generate the absolute maximum amount of cash flow that we can out of them. Look, you know, your point's a very good one. We've been maintaining some coverage just because the business has outperformed, and historically, we've used that to pay down debt. Obviously, at sub $60 million of debt today, again, we're about to pay the distribution, so that'll step up a bit, but we're getting, you know, pretty close to zero in terms of total debt on the balance sheet. I think what that means over time is just that, you should see payout ratios go up. With very little debt left to repay, I think that the general thinking of the board, and of course, this could change, but it's something we talk about every quarter, is that we'll return more of that cash flow to our shareholders, through higher distributions. Again, we'll see other things. We do have the preferred outstanding, which we think is a great security, and Carnelian has been a wonderful partner. Someday we'll need to think about what to do with that. In the meantime, I think with the strength of the balance sheet, it just means that that payout ratio goes up. Got it. All right. That's it for me. Thanks, guys. Thanks, Joseph. Appreciate it. Thank you. I see no further questions in the queue. I will hand the call back over to Tom Carter for closing comments. Okay. Well, thank you all for joining us today, and we'll talk to you next quarter, and have a good day. This concludes today's conference call. Thank you all for participating. You may now disconnect. Have a pleasant day.