Brigham Minerals Inc (MNRL) 2020 Q2 法說會逐字稿

Good morning, and welcome to Brigham Minerals Second Quarter 2020 Earnings Conference Call. (Operator Instructions) Please note that this event is being recorded. I'd now like to turn the conference over to Mr. [Chris Catton], Investor Relations. Please go ahead.

Thank you, operator, and good morning, everyone. Welcome to the Brigham Minerals Second Quarter 2020 Earnings Conference Call. Joining us today are Bud Brigham, Founder and Executive Chairman; Rob Roosa, Founder and Chief Executive Officer; and Blake Williams, our Chief Financial Officer.

Before we begin, I would like to remind you that our remarks, including the answers to your questions, contain forward-looking statements, and we refer you to our earnings release for a detailed discussion of these forward-looking statements and the associated risks.

In addition, during this call, we make references to certain non-GAAP financial measures. Reconciliations to applicable GAAP measures can also be found in our earnings release.

A couple of administrative items. We have a new investor presentation titled Second Quarter 2020 Investor Presentation available for download on our website, brighamminerals.com. We recommend downloading the presentation in the event we refer to it during the conference call.

Lastly, as a reminder, today's call is being webcast and is accessible through the audio link on our IR website.

I would now like to turn the call over to Bud Brigham, Founder and Executive Chairman.

Thank you, Chris. We appreciate everyone joining us this morning on our second quarter 2020 earnings conference call. The second quarter was extremely challenging for the oil and gas industry. I've experienced numerous cycles over the years, but this one is certainly unique.

During the second quarter, prices reached record lows, and as a result, activity was significantly impacted. In particular, across the different basins and the liquid-rich resource plays that we monitor, we saw 70% to 90% of the rigs laid down and 90% of the frac crews idled, a drop from approximately 190 frac crews in February to less than 20 by early May. Free markets were responsive to the pricing signals, with operators rapidly and responsibly reducing their activities and curtailing production and as a result, the industry is recovering faster than most expected. However, this has been an extreme cycle. And as such, we expect financially challenged operators to liquidate or consolidate with larger entities and that surviving operators will focus on drilling their highest remaining rate of return wells.

A great example of this expected consolidation is Chevron's recently announced acquisition of Noble Energy. Subsequent to the acquisition, Chevron will operate 8% of Brigham Minerals' undeveloped inventory, and we are thrilled to see our assets migrate into the hands of a larger, stronger company whose balance sheet will enable more consistent resource development. This is the Darwinism of the oilfield that we've experienced time and again over the years. The core leasehold that Brigham Minerals owns minerals under continually migrates to the top-tier operators with the strongest balance sheets. Chevron's performance during the second quarter relative to Noble's illustrates how beneficial we expect this consolidation to be for us. During the second quarter, Noble dropped all their Delaware Basin rigs, while Chevron continued to run, on average, 5 rigs.

As previously stated, because our leasehold is core, we benefit from its migration to these large operators, such as Chevron, given their unmatched ability to pursue sustained development throughout commodity price cycles, thereby generating optimal development and cash flow generation for Brigham Minerals.

In addition, we are just starting to see the ground game acquisition pace start to return to a more normal level. We have been patient and are now seeing a number of potential sellers come back to us and adjusting to the post-COVID post-OPEC+ adjusted offer prices. Further, as always, we continue to engage in the evaluation of larger transactions and believe that similar to the consolidation we're seeing among E&P operators, we're going to see a wave of consolidation in the mineral space. In our view, it's important to achieve scale, and nobody is better positioned to accomplish that in the premier liquids-rich basins than we are.

I also want to point out that it's in stress periods like this, when companies are challenged by macro headwinds, that dispersion and relative performance is most evident. While others are holding back distributions to fortify their balance sheets, we, as promised, are distributing 100% of our distributable cash flow. Further, with no net debt, we are loaded up to acquire, while others are impaired in the sweet part of the cycle. We are very excited about the opportunity in front of us to create substantial value for our shareholders via acquisitions.

Lastly, I'm extremely excited to welcome Lance Langford to the Board of Brigham Minerals and officially back into the Brigham family. Lance is a proven value creator with extensive expertise across the oil and gas value chain from upstream and midstream, all the way to minerals acquisitions. At Brigham Exploration, Lance and his team revolutionized the Williston Basin by pioneering significant advances in completion techniques through cutting-edge adoption of some of the very first long lateral wellbores with 20-plus frac stages. These technologies and Lance's vision and technical leadership were instrumental in Brigham Exploration's industry-leading success and our eventual sale to Statoil in 2011 for $4.4 billion. Lance subsequently gained extensive leadership and personal experience leading a large organization with Statoil before forming both Luxe Energy and Luxe Minerals. Importantly, while with Luxe Minerals, Lance and his team went on to acquire a substantial mineral position in the Permian Basin.

I'm extremely excited about Lance's appointment to the Board and believe he will contribute extensively to our efforts to drive continued excellence and push our teams to stay at the cutting edge of the oil and gas industry, both of which are critical to our goal of consolidating the mineral space.

With that, I will turn the call over to Rob to cover our operational results.

Thanks, Bud. First, I want to thank all of our Brigham Minerals employees who have continued to operate at a very high level during these unprecedented and challenging times. We began the transition back to the office in mid-May on a rotating basis, and they executed another quarter reporting cycle flawlessly. In the face of these significant challenges, I think it's important to review several key factors as we think about a recap of the second quarter and the outlook for the remainder of 2020.

First, in the second quarter, we continued to pay out 100% of our distributable cash flow to our shareholders. With close to $17 million of cash on the balance sheet as of June 30, we again delivered upon our promise to pay out 100% of our distributable cash flows. Our dividend was down compared to the first quarter, but the decrease was largely driven by the roughly 50% sequential decrease in energy prices related to the demand disruption associated with the economic shutdowns implemented to attempt to rein in the COVID-19 pandemic. Additionally, our dividend was impacted by shut-ins during the quarter, which reduced our average daily volumes by around 700 barrels of oil equivalent per day. Ultimately, we expect to benefit from these shut-ins as these barrels should be produced in the future at higher and more sustainable oil prices.

Second, our outlook for the remainder of the second half of 2020 has improved with the rebound in crude oil prices that occurred in June and that's continued into the third quarter. Already, we estimate that crude oil pricing is, on average, approximately 50% better through the month of July as compared to the entirety of the second quarter. Next, the shut-ins that we experienced in the second quarter already appear to be coming back online and thus will positively impact the third and fourth quarters of 2020. In particular, we are already starting to see Continental Resources bringing back online their Oklahoma volumes very late in the second quarter, and those volumes will positively impact our results for the remainder of the year.

Third, our DUC inventory remains strong with 4.6 net DUCs in inventory at the end of the second quarter. Importantly, approximately 60% of our DUCs are located in the Permian Basin, and drilling down in additional detail, approximately 17% of those DUCs are operated by ExxonMobil, who, based on research, has rapidly increased their frac fleet over the past several weeks and during July, average running 3.5 frac crews, which is the highest amongst the operators we monitor. Further, and I believe we've indicated this on past calls, we actively monitor satellite data and determine when we believe frac crews have arrived on our drilled but uncompleted drilling spacing units or DSUs.

Our analysis of recent satellite data indicates that approximately 1/3 of our DUCs have been treated or fracked to date. Ultimately, our operators will decide when to turn those wells online to production, but we believe these wells represent the fastest and most capital-efficient production for our operators. And assuming continued market stability, our treated DUCs should provide the cornerstone for improved and stabilized production during the second half of 2020.

To summarize my second and third points, and again, assuming current market conditions hold, we believe shut-in volumes returning online and treated DUCs being turned in line to production should result in production volumes for the second half of 2020, stabilizing and averaging in excess of 9,000 barrels of oil equivalent per day. This outlook represents return to production volume growth versus the second quarter.

Fourth, based on increasing deal flow that really transpired post the 4th of July, it appears we are seeing a falling of the mineral acquisition market. We purposely reduced our acquisition activity in the latter half of the first quarter and largely through the entirety of the second quarter in order to preserve liquidity and maintain optimal balance sheet flexibility and thus position ourselves to capitalize on more attractive opportunities we expected in the second half of the year. That's playing out well for us now.

Our deal teams are fully engaged, working up our ground game acquisitions, our singles and doubles as well as continuing to work on our larger transactions. Thus far, in the third quarter, we've already closed or have under PSA a number of highly attractive transactions totaling approximately $15 million. Of course, we still have to run title on the deals that we PSA-ed, so there's potential closing risk, but we've historically closed a very high percentage of our deals and don't anticipate a different outcome in the third quarter. Excitingly, and as I indicated would be our focus during our first quarter conference call, we anticipate deploying more than 90% of those acquisition dollars to the Permian Basin. And further, we anticipate that of the aforementioned deals, more than 2/3 of our capital will be deployed to Loving County. With our undrawn revolver, Brigham Minerals remains optimally positioned to continue to capture acquisition opportunities such as these during the remainder of 2020.

Turning to a review of our operating results. Our second quarter production volumes were down 15% sequentially to roughly 8,900 barrels of oil equivalent per day. As I've already mentioned, the majority of the decrease related to operator shut-ins of approximately 700 barrels of oil equivalent per day. Our total shut-ins, close to 2/3 or about 450 barrels of oil equivalent per day, related specifically to Continental Resources volumes and in the Anadarko and Williston basins. Of the entirety of our remaining portfolio, we anticipate that only 3% of our volumes were shut in, which is a positive outcome given the significant shut-ins disclosed by operators during the current earnings cycle. DUC conversions, or wells turned in line to production and thus subsequently classified as proved developed producing locations, during the second quarter, did slow relative to the first quarter, which is largely a result of the aforementioned decrease in frac fleets and the likely deferral of bringing online wells to production that have been treated until a more normal pricing environment presented itself.

During the second quarter, we converted 1.2 net DUCs or 21% of our net DUC inventory available at the start of the second quarter versus 1.9 net DUCs in the first quarter, which represented 32% of our DUC inventory at year-end 2019. As I look to our DUC inventory at the end of the second quarter, it's strong, with 4.6 net DUCs of which 60% are positioned in the Permian Basin. Further, the majority of our DUCs are operated by ExxonMobil, Continental Resources, Crestone Peak, Chevron, PDC and Shell.

Looking ahead, I would point to the rather positive fact that, as I previously mentioned, it appears that we do have a meaningful percentage of our DUCs in inventory that are ready to be turned in line to production by our operators. Again, about 1/3 of our DUCs have been treated and could be rather quickly turned in line to production and contribute to our production volumes in the third and fourth quarters when and if operators decide to do so. Additionally, our permit inventory remains strong with 4.5 net permits in inventory at the end of the second quarter. Approximately 50% of our permits on the DJ Basin and 40% of our permits are in the Permian Basin.

Lastly and as Bud pointed out, we are excited about the Chevron agreement to acquire Noble. In particular, this will result in 8% or almost 9 net undeveloped locations being drilled for us by Chevron, of which 7 net undeveloped locations are anticipated to be located in the Permian Basin and 2 in the DJ Basin. As a result, Chevron now becomes the second largest operator of undeveloped locations on our operator wheel. We are excited as Chevron has continued to focus on the southernmost portions of Reeves County, with particular emphasis in the block 51 T-8-S portion of Reeves County where they currently have a rig running and largely have had a rig running since 2017 and are continuing to issue permits. As we look at this portion of the Southern Delaware, Chevron and Noble, in essence, have a highly contiguous position in the integration of those 2 positions to optimally position Chevron to drill 10,000-foot laterals across the significant area where mineral owns approximately 2,000 net royalty acres. In fact, in July, Chevron just issued 4 permits across a half section in this area in their REV BX 11 unit where Brigham Minerals has an interest.

With significant capital deployed and a much higher probability of deploying rigs on a consistent basis, I think you can understand why we get excited about M&A activity in our basins as more than likely, given our propensity to stay under the very best rock, the acquirer is going to have purchase leaseholds where we also own the mineral. Overall, our portfolio performed well, considering the very challenging backdrop and most importantly, our company is poised to capitalize. We're debt-free with cash on the balance sheet and actively on the hunt for accretive core mineral acquisition opportunities.

I'll now turn the call over to Blake, so he can summarize for you our financial performance. Blake?

Thank you, Rob. While this environment is certainly challenging on several fronts, our business model and clean balance sheet set us apart from our peers and other energy-related investments. Not only are we in an advantaged position to execute on our acquisition strategy through our ability to fund accretive growth opportunities, but also to return capital to shareholders. Further, we still do not have any debt outstanding, which, coupled with our unhedged production, will allow our shareholders to fully participate in the recovery in commodity prices and activity through the maximization of distributable cash flow.

Looking at our balance sheet, we had $16.5 million in cash and an undrawn revolving credit facility with a capacity of $135 million as of June 30, giving us total liquidity of about $150 million. Capital structure is important in our highly cyclical industry, and we will remain mindful of that as we deploy capital to acquisitions by ensuring we limit our net debt to adjusted EBITDA ratio to less than 1.5 or 2x.

Our daily production for the quarter was approximately 8,900 barrels of oil equivalent per day, down 15% sequentially though up 31% from the same period last year. Product mix was roughly flat at 71% liquids. Our oil cut decreased due to impacts from reduced Permian and Williston volumes as well as gas and NGL type curve outperformance relative to our expectations, in particular, in the DJ and Delaware basins. We continue to expect our oil cut to fluctuate quarter-to-quarter, but trend back towards our normalized run rate of closer to 55%.

Our portfolio generated royalty revenue of $12.5 million for the quarter. We did not generate meaningful lease bonus this quarter and expect that to continue for the remainder of the year. In this environment, we are focused on maximizing option value through high-impact upgrades and qualitative lease improvements and have significant leverage with operators to do so.

Net loss for the quarter was $6.8 million. Adjusted EBITDA for the quarter was $5.9 million. And adjusted EBITDA, excluding lease bonus, was also $5.9 million. Producing positive EBITDA despite significant pricing and activity challenges is another unique aspect only possible in a minerals business.

Realized pricing for the quarter came in at $15.57 per BOE, down 48% from the first quarter. By commodity type, realized pricing was $24.15 per barrel of oil, $1.11 per Mcf and $7.28 per barrel of NGL. On costs, gathering, transportation and marketing expenses were $1.6 million or $2.02 per BOE. Severance and ad valorem taxes were $1 million or 8.2% of mineral and royalty revenue.

G&A expense before share-based compensation was $4 million. G&A includes approximately $700,000 of expenses associated with our June secondary offering and other annual costs. Excluding these costs brings G&A to $3.3 million and on track to achieve our G&A cost reduction goals described in the first quarter.

Lastly, we declared a dividend of $0.14 per share of Class A common stock, which is down from the $0.37 last quarter, primarily due to declines in realized prices and production as well as a reduction in lease bonus, which is historically irregular in timing and size and contributed $0.07 to our first quarter dividend. This dividend represents all of our discretionary cash flow for the quarter. We also do not anticipate paying federal income taxes for the first half of the year and are, therefore, returning roughly $2 million of cash to shareholders that was withheld for tax payments in Q1. In essence, we view the inclusion of our lease bonus in the first quarter and the return of tax withholdings in the second quarter as the continued desire on the part of our Board and our management team to the return of capital as expeditiously as possible to our shareholders.

We are excited to see many operators such as Devon and Pioneer migrating towards our established approach of variable return of capital. The $0.14 dividend is payable on September 3 to shareholders of record as of August 27.

I will now turn the call back over to Rob to wrap things up.

Thanks, Blake. We appreciate you joining our second quarter 2020 call. Operator, I'll now turn the call back over to you to begin the question-and-answer portion of our conference call.

(Operator Instructions) First question comes from Chris Baker of Crédit Suisse.

Just on the acquisition front, great to see the improvement in pricing. And I think looks like third quarter came in, call it, 45% lower than the first quarter on a dollar per location basis. Can you just talk about some of the major drivers behind that improvement? Maybe on commodity prices. Just trying to get a sense of how sustainable these much better prices are likely to be for the rest of the year.

I appreciate the question, Chris. Obviously, we're pleased to see the activity levels for us pick up again. Obviously, as we indicated on our May call, we thought that there would be a pause in the activity. We did see that happen in the latter part of the first quarter and throughout probably the majority of the second quarter, but that's not unexpected given what we lived through in 2015, 2016. So knowing that there'd be a slight pause in activity, we knew it was in our best interest to remain disciplined, patient in our underwriting of potential deals. And so integrating the new data such as pricing, rig activity levels, frac crew levels, what the impact of permits and DUCs should be as it relates to valuation models, et cetera, all went into the calculus of the offers that we put out.

And so we did remain engaged, putting out offers throughout the entirety of the second quarter because really, we thought that, that was in our best interest just to reset from the seller's perspective what the new pricing for minerals should be given the current market conditions. And so a lot of that, probably 3 to 4 months of limited buying activity was really to reset expectations. And so now I think you've seen that happen. We do think -- or I at least think for a time here and probably throughout the remainder of 2020, as sellers think about their mineral position and really the continued signaling of operators as it relates to lower activity levels related to -- versus the past, the rig counts where they are today relative to the past. I think longer-term or at least here throughout the remainder of 2020, you're going to see folks kind of the realization there, that pricing is different, and hopefully, that is sustainable.

So I think to the extent you do see operators being more disciplined, you'll continue to see pricing more akin to the levels that we're estimating and seeing in Q3 here. And that's roughly that $3.7 million per net location, Chris, that you're talking about.

Great. That's helpful. And then just as a follow-up, you guys mentioned remaining interested in larger scale acquisition opportunities. Can you just maybe talk about how that framework might have shifted post oil price crash?

I think one of the big things that we think about when we think about a larger deal is to continue to maintain a liquidity flexibility going forward, even announce it post a larger deal. And so the discussions now are centered upon more of taking the entirety of the consideration back in terms of equity thus leaving the balance sheet much as it is today. And so we can continue on with those singles and doubles, the ground game that we've undertaken throughout because we've spent the past 7 to 8 years building that ground game network. So it's really not in our best interest to try to over-lever a transaction or otherwise take on debt to fund the transaction and instead fund that through almost entirely equity because it gives us a lot of flexibility to continue to buy with in the future because we do think and continue to believe that we have tremendous opportunity to continue to compound value going forward via our acquisitions.

And that's what's really buying when you buy into Brigham Minerals, it's that 40-person team, half of whom are on the acquisition side evaluating every deal that comes in, every section to make sure we're paying the proper price, undertaking a very disciplined process and continuing to generate those leads. So it's imperative that even upon doing a big deal, we have that flexibility going forward to continue with our ground game.

The next question comes from Brian Singer, Goldman Sachs.

You talked about the benefits of both shut-in production curtailments coming back online as well the DUCs that will help push production greater than the 9,000 BOE a day mark on average in the second half. To what degree do you see that as temporary? Or in your conversations with the operators, what level of activity and what is the likelihood of that activity that you would need to see to sustain or grow that 9,000-plus or 9,000-type BOE a day in 2021?

I think one of the keys is that as you think about our portfolio in general, is our continued propensity to stay under the best operators under those very best areas, the core geology that's going to continue to see rigs deployed to the position, capital to deploy to the position, also our continued desire to stay in that northern portion of the Delaware Basin, northern Loving, Reeves, Southern New Mexico, such that, that seems that the higher activity levels of late as well.

And so I think because of our -- really the philosophy that we've undertaken from the very beginning in terms of making sure we stay in the very core parts of the basin, the most economic of the basin that operators are going to naturally migrate and deploy that capital to their most economic locations. So we're hopeful with operators acting in a rational basis that with that realization that some of our locations are the most economic in the basin, even at kind of a maintenance level capital expenditure levels, you'd see a disproportionate level of activity directed to our position. And so our hopes are that given that philosophy, that you'd continue to see growth as we think about 2021 going forward.

Great. And then my follow-up goes back a little bit to, I think, the M&A. In Bud's opening comments, you talked about the benefits or you talked about the need for and the interest in gaining scale. For operators, that scale is -- you really see that with regards to the F&D cost, the cost structure and the ability to execute. Can you define how you see the benefits of scale in your business model and how investors can best measure that?

Yes. Clearly, we've got an exceptional technical team here that's executing on our ground game acquisitions and also evaluating the larger opportunities. And so scaling up our -- the enterprise, our reserve base in production and cash flow, there's going to be a lot of leverage there associated with that because this team continue to execute on the ground game. But on a larger base, there's just immense leverage there.

And it's something investors want to see as well. I mean, we already enjoy exceptional margins but there's a clear opportunity to be a more appealing enterprise to a larger pool of investors. Blake, you guys may want to add.

Yes. The only thing I'd add is that larger scale helps mitigate development timing. So to the extent we've got more acreage in the right areas and the right operators. It's going to help mitigate some of that timing risk.

Yes, I'd reiterate the investability point that Bud made is an important one just to continue to broaden the set of investors that can invest in Brigham Minerals. I think also, when I think about scale, it's the sizing of the RBL. Much larger RBL allows you a much longer runway to continue to buy with our ground game acquisitions. And then obviously, there's the margin piece of the G&A, such that we have to add very few employees to manage a larger enterprise, given the systems. And we've been at this 7 plus years. So I think that the scale benefits come in numerous different forms and just not necessarily operating margins.

The next question comes from William Thompson of Barclays.

Maybe to follow up on Brian's first question. It sounds like with Continental bringing on those volumes in Oklahoma, that would obviously benefit -- may benefit to 3Q. Just thinking in terms of the timing of those DUCs that haven't been tilled, how we should think about the cadence from 3Q to 4Q? And then it sounds like we'll kind of go back to the historical trend of 55% oil mix? I just want to make sure we confirm that.

Yes. I think a couple of the factors as you think about that oil cut going up to the 55% is the return of the shut-in volumes that you mentioned. And so as we think about the shut-in volumes being largely Continental's volumes there in the SpringBoard play, where it is more oilier volumes than the Williston Basin. That should help improve the oil cuts. And then as well, when you think about that DUC percentage being 60% Delaware Basin focused, that should incrementally also help the oil cuts. So I think there's some real important factors there that will continue to improve the oil cuts and help address that. Blake, did you want to...

Yes. I think that's right. We also had, on the oil cuts, there was a bit of NGL and gas type curve outperformance in the quarter. But just to confirm, we do expect that to go back to that 55% run rate that we've had in past quarters.

Yes. And I think as you think about Continental and bringing those volumes back online here in the third quarter, they've signaled in their communications that second quarter volumes are roughly 200,000 barrels of equivalent per day in the third quarter ramping to 290,000. And then the fourth quarter, the exit rate is 320,000 barrels a day. So it's clearly indicative of them bringing the shut-in volumes back online and into play.

And then I think about the DUCs in general, in that percentage, we've continued to see frac crews, improvements in frac crews deployed to our basins. And that's something that we monitor on a week-by-week basis. Bud alluded to the fact that when you look at the data and towards the end of February, you're at 190-plus frac crews in some of the key basins that we monitor. And then within a 10-week period, that frac crew total went down to less than 20. The great part is we've seen that, that doubling of the frac crew, so mid-40s in terms of frac crews and in the basins that we monitor. And in particular, I alluded to it in some of my comments, the XTO frac crews being substantially higher relative than in the past or here recently. And so with them controlling 17% of the DUCs, that's very conducive to us being able to hit the guidance that we put forward.

So I think as you think about the natural progression of DUCs and operators ramping up activity, it's just natural to expect that the conversion percentage in the third quarter would likely to be slightly less than the fourth as that activity levels pick up. And a lot of operators are indicating that they will be picking up frac crews here September-ish and throughout the late remainder of the year. I think a lot of it is just real positive that you're seeing from operators in terms of their indications that they're resuming to more normalized activity levels because when you think about it, it's really pretty astounding. You look at the kind of the 30 key operators we watch, 20 of them had frac holidays during this period, but 10 of them have already gone back to work. So you're seeing those operators come back and be active again. So I think it's very conducive to us being able to hit that average of 9,000 barrels a day that we alluded to in the press release yesterday.

I might add, I think one thing is -- and I might emphasize that we can feel good about the visibility of the frac crews increasing on a quarterly basis, really all the way through to the first quarter of '21. So -- and then I think you're going to see a follow-up on that with the drilling rigs because, as Rob talked about in his, I mean, operators are motivated coming out of this portion of the cycle to focus their activity on the opportunities they have that generate the best margins and the highest IRR. And of course, that means our minerals. And so I think that gives us a lot of comfort with accelerating activity, both on the frac crews and then as well with the rigs.

Helpful color. And I guess as my follow-up on Slide 11, obviously, it appears here, you added some incremental acreage in (inaudible) New Mexico in your comments. You talked about some activities. I'm just curious. Based on the concentration of rig activity in New Mexico, can you just remind us your federal [and] exposure? And two, what you think would happen in terms of maybe some of those rigs migrating back into Texas in terms of having an issue -- if Biden gets elected and we see kind of an issue around permitting?

Yes. So just as a reminder, our overall mineral position, we're 89% fee minerals. So those were minerals kind of unburdened by kind of the federal regulatory issues that might be happening here post the November elections. 8% of our minerals are state minerals within the state of Texas. So obviously, given the propensity and the positive response to Texas oil and gas industry, don't see any risk there. The remaining portion of our minerals, roughly about 3% are in federal units. And so that's just not in New Mexico. You do have federal units in North Dakota and Oklahoma. And so roughly, that's about 1% in federal units of our mineral position in New Mexico, Oklahoma and North Dakota. And so one of the -- we've historically kind of reduced our activity levels in New Mexico relative to Texas just because of that potential issue as it relates to permitting, et cetera. A lot of talk regarding the length of the Permian process, how much harder it is in New Mexico. So there's always much more clear line of sight to development in Texas relative to New Mexico.

I do think the EUR, as you mentioned, seeing elevated rig activity levels in New Mexico today relative to the past, and for instance, I think if you look at the stats, roughly about 60% of the rigs in the Delaware Basin are on the New Mexico side of the basin. And I think that's largely, as you heard some of the commentary by some of the operators here to address kind of the impending potential risk in New Mexico as it relates to potential federal frac ban, and so I would assume that if anything does happen in the future, the vast majority of those rigs are going to naturally migrate south of the border, and you're going to see much higher elevated levels of activity in Texas, which would be very beneficial to us as we think about our portfolio and how we've structured it.

The next question comes from Pearce Hammond, Simmons Energy.

My first question is, thanks for the second half of '20 production guidance. Do you expect the oil mix to be similar as first half '20 or better given the production curtailments, which occurred in the second quarter?

Yes. As I was saying before, Pearce, we expect that to migrate back to that 55% that we've historically seen.

Okay. Perfect. And then my follow-up question pertains to kind of the puts and takes of dealing with large producers. And so in the prepared remarks, Bud highlighted that the Chevron-Noble acquisition will be beneficial as it will place more of your minerals in the hands of a large, well-capitalized operator. I was just curious what you see are the puts and takes of dealing with large producers, like someone like a Chevron because one could argue that they have a wider choice of places to deploy their capital around the world, and may not be as responsive to higher oil prices driving improved activity as would be an independent. So just curious, your puts and takes around dealing with these larger, better-capitalized producers.

Well, this is Bud. I'll take the first shot at that. I do think 5 or 10 years ago, it was quite different. The -- it was the independents, the more entrepreneurial independents that were making it happen in U.S. shale. But I think now it's -- to a large degree, the factory has been built, and it's about execution. And so I do think this Darwinism is so beneficial for us at this stage because I think the majors are finally, in my view, understanding that it's very difficult for the international projects to compete with U.S. shale and particularly coming out of this cycle. It's my view that they're going to increasingly lean on U.S. shale for their stable base of growth in production, particularly, obviously, given the political risks associated with a lot of the international endeavors.

So I think it's -- and as you would expect and as we touched on, these large operators with the strong balance sheets, they want to own the very best assets. And so it really just -- it just evidences our belief all along. At Brigham Minerals, we want to focus on the best of the best, kind of like real estate. And by doing that, you're subject to less volatility and even through the troughs. And I think we're demonstrating that. So I think that's going to continue to play out that the -- where you have a weak operator with a weak balance sheet, they're going to get taken out by a stronger operator with a better balance sheet and that's going to benefit our asset base and the monetization of it. Go ahead, Rob.

Yes. No, I think that when you think about the kind of the option to terminology that you used, I think, in particular, you think about these larger operators. You're almost buying a floor option in that you're mitigating your risk to the downside by having continued deployment of rigs and activity to your position. Bud alluded to some of that. At the time of the announcement of the merger, Noble wasn't running any rigs in the Delaware Basin. Chevron, 5 or so on average over the second quarter. So tremendous ability there to continue to develop even in the down cycles.

A couple of the other real positives, I think, as you relate, think about the much larger operators, which are larger balance sheets, and you think about the overall tank development of each spacing unit, those larger operators are going to be able to drill the 15, 16 wells within 3 or 4 different producing horizons that might otherwise communicate if they're produced independently or at slower rates. And so it's going to lead to overall higher recoverability of the mineral resource that we own. So I think that's a huge positive. When you think about the deployment -- being able to deploy large amounts of capital to one single unit, bring all of those wells online at the same time, frac them all and allows for the EURs within each of those wellbores to be maximized on our part.

And then I think as you think about these larger operators and even though they do have relatively big positions, you think about your ability to fine tune and invest in the highest rate of return projects that they have. So when you think about -- and this is whether it's Chevron and then buying Noble or Oxy. Historically, we've stayed on the eastern side of the Delaware Basin that's been more oily. So as you think about these operators and their ability to accelerate activity, you think it'd be naturally to those oilier parts of the basin on the eastern side. And in particular, as you think about that Chevron-Noble deal and you look at that area that I pointed out there in the Southern Delaware Basin, it's very oily relative to some of the Culberson position that you have there, that Chevron is drilling with Cimarex and others. And so we're very pleased that we are in these highly -- our higher oil cut areas that we would anticipate will be drilled on an expedited basis relative to kind of the western side of the Delaware.

Yes. The only other thing -- of the value chain as well as have leverage over that value chain, so in keeping with the full development aspects of their abilities, that will bode well for us also as they've got midstream, they've got refineries, all of those things.

The next call is from Leo Mariani of KeyBanc.

I think kind of pre-COVID, you guys had an expectation that you might be able to do just over $200 million of acquisitions annually. You clearly talked about the pace starting to pick up again here in the last month, which is very nice to see. Just trying to get a sense from a magnitude perspective. Do you guys think you can kind of get back towards this $200 million type of run rate later this year? Or do you think maybe that would take a little while to kind of revisit here?

I think we're going to ramp into that kind of $50 million a quarter pace. I think, as you mentioned, we've seen some really nice incremental activity in really starting post-4th of July through current. And so the deal team has been extremely busy, working up those singles and doubles. So really a great response from the deal team to keep up with that deal flow, get us through the quarter as well as to continue to work up those larger transactions that we've been looking at. And so I think, as you think about the third quarter, we might be on a kind of a $20 million to $25 million to $50 million acquisition pace and then ramping up to higher levels there in the fourth quarter, maybe targeting kind of $37.5 million midpoint. I'm just obviously thinking about this now that you have asked the question, but I think it's going to be ramping into that $50 million a quarter pace. And I'd be hopeful, given our balance sheet and the activity levels, we'd be closer to that $50 million of capital deployed level early into 2021.

I think there's just, as Bud mentioned, a tremendous opportunity here to continue to acquire and consolidate. And so it's our job to be responsive to mineral sellers when they are thinking about selling and getting back to them as quickly as possible because I do think on an overall basis, when you think about some of the other commentary provided here recently within the conference call, there's a real unique ability for us to be the public consolidator within the basins. And so I think we need to do everything possible to endeavor to take advantage of that situation while it's present, and so -- with the understanding, obviously, that we're going to be -- continue to be very disciplined in our underwriting approach consistent with what we've done in the past is the key.

So there's multiple things that we're balancing, wanting to do deals but then also being consistent in our approach in the deal evaluation phase as well. So I think you'll see us ramping in soon. And I do think that, that $50 million a quarter level is achievable and probably seeing us hit that probably Q1 of next year.

Okay. That's great color for sure. I was hoping you guys can maybe speak a little about any potential to use the balance sheet for stock buybacks. Obviously, all energy equities have really gotten hit during 2020, I guess, which is a huge surprise, given the downdraft in oil. But just given how clean your balance sheet is, have you looked at all at stock buybacks to potentially supplement some of the M&A? Because effectively, I guess, you'd certainly be kind of buying back existing minerals in the portfolio pretty cheap at these levels as well.

Sure. Sure. And Leo, we are always evaluating all of our acquisition opportunities, including ourselves. And while we certainly think that we're undervalued at this time, we're pretty excited about the acquisitions that we've been able to execute on and get under contract here in the third quarter. So with the -- with that dollar per net location dropping to $3.7 million, we're pretty excited about putting capital to work with those acquisitions at the moment.

Yes. And this is Bud. I might add, the private market for assets is also less competitive. There's less capital out there chasing minerals. And we certainly believe we represent the premium public liquidity option for a lot of mineral owners out there in the premier liquids-rich resource plays.

Next question comes from Kyle May, Capital One Securities.

So putting aside the additional expense related to the secondary offering, it seems like your OpEx was elevated in the second quarter on a per unit basis. Can you give us any color on what drove the change in the second quarter and how you see things trending going forward?

Yes, sure. So obviously, we -- as you mentioned, we did have some costs associated with that secondary offering in June that's running through G&A there. We also had some more annual-oriented costs that we don't expect to see in the third and fourth quarter. Those are tax-related and annual meeting-related, those types of things. So those won't be there in the second half. We have made headway on our G&A cost-saving initiatives that we announced in the first quarter, hammering on a lot of our service providers and have been able to achieve a lot of those savings.

As far as some of the other costs, GTM is largely $1 per barrel. So as prices per barrel increase, that should level out more in line with what we've seen in the past. And then as far as severance and ad valorem taxes, those are normally percentages of revenue. You did see a little bit of an uptick from the first quarter. Some of that's related to the ad valorem taxes being property taxes and having a little bit stickier value that's more caused by valuations from last year effectively. So again, as prices increase, that should level out back to kind of where we've seen it in the past.

Got it. Okay. That's helpful. And I know you talked about your -- I guess, your capital thinking for larger strategic acquisitions, but can you give us an update on kind of what you're seeing or hearing from sellers of those larger packages?

I think sellers are equally understanding that maintaining a clean balance sheet is important. If you think about a larger deal, that seller is going to be taking considerable equity back from us. And so they'll want to see that equity trade well. And so I don't think it's in anybody's real interest to do anything other than a largely equitized deal. And so I think that will be critical. There is the understanding that it would take them a while to unwind that position if they wanted to. And so if you think about being a long-term shareholder, it's in their benefits to take back equity, such that they provide us with the runway to work with to continue to capitalize on our ground game that I mentioned that we've been working at for 7 to 8 years to develop.

And so I think there's equally that realization on their part that, given the current environment, it's best to maintain significant balance sheet flexibility such that if they think about unwinding the position, say, over an 18- to 24-month period, that there's runway for the company to continue to work with, seek share price appreciation going forward as we continue to generate value by acquiring. And so I think it's rational for a seller to think in that manner.

The next question comes from John Freeman of Raymond James.

On the last few years, you've had a pretty consistent sort of annual DUC conversion rate of that 86% to 88%. The production guidance that you all have got now for the second half of the year, what does that translate to for kind of your updated assumption for what the annual DUC conversion will be this year?

So just as a reminder, so the DUCs that we converted in the first quarter were roughly 30% of the net DUC balance that was on hand. Thus far, when you then incorporate the second quarter conversions, we're at 50% or so at the midpoint of the year. And so when you think about roughly about 1/3 of those DUCs already being fracked, you've got another 30% of our beginning of the year frac balance in hand that should be converted this year. So you're already looking at kind of, say, an 80% DUC conversion number in 2020. And that's assuming that there's no further DUC conversions, which we anticipate there will be, given kind of the rig -- the ramp-up in the frac fleets that we're seeing today. And so I'm hopeful that we're going to be closer to that 90%, when you think about already being at that kind of 80% increment already. And so just a small amount of incremental activity on behalf of our operators can clearly push us to that 90% level again.

So I'm very confident or feel good that we'll be in that 90% range again, given where we are today, the knowledge about DUCs that have been treated and then just how much small of an initial increment's required to get us back up to that 90% level.

That's great, especially given how unprecedented everything else we've gone through that you'd still be at that high of a rate. The follow-up question I had, previously, I think you all talked about kind of a 36% base decline rate 2Q '20 to 2Q '21. What is -- based on the production outlook for the second half of the year, do you have sort of a rough assumption of what the 4Q '20 base decline rate would be based on that production outlook?

Yes, I think it will be -- we're looking into it right now, but I would expect that it will be about the same.

There's really been no major shifts in the portfolio when you think about the areas that we're operating under, the basins or the consistency of the addition. So I don't think there's really anything inherently different that would cause us to really change or shift our thoughts as it relates to the decline rates of the portfolio that we've talked about in the past.

Next question comes from TJ Schultz with RBC.

You've mentioned a couple of times on buying packages more fully with your equity to keep the balance sheet intact and sellers want to see this too. So is there really no appetite to put on debt now for deals? You've talked before about targeting 1.5 to 2x debt leverage as you deploy capital, but has that changed?

Well, I think when we think about adding debt to the balance sheet, it's largely really to capitalize on those ground games, kind of those deals that are, say, $0.5 million to $1.5 million apiece, that it's really not feasible for that seller or they're not really interested in selling for equity. Really, they're selling because there's a need for cash to fund whatever might be currently going on their life or wanting to diversify out of oil or diversify out of operators, et cetera, certain operators.

And so I think as we think about it, those deals will be the deals that would be funded by the debt piece. And so as we continue to capitalize on the consolidation thesis and capitalize on the ground game opportunities that we're seeing, that will be kind of the toggle such that those acquisitions will be funded by debt while leaving the equity piece to be utilized for the larger deals.

Okay. Makes sense. And then on the larger deals, are those 2 primarily Permian [package] that you're looking at? Or are you looking at deals or considering any with assets outside the Permian or even outside your current footprint?

I think there's actually quite a few larger deals in the queue that we're working. And so those are spread amongst basins, et cetera. So we don't want to, in particular, talk about any one transaction. But I would say our focus has been the Permian and probably will be going forward, and so that's largely where we're focusing our efforts. But that's not to say that there aren't other packages that might include a Permian plus other piece. And so I think when you think about our technical teams and our diversified portfolio, to the extent that there is a diversified deal out there, there's probably nobody else better in the marketplace to quickly evaluate that deal and get a response to the seller just because of our experience having worked all these basins over time.

But I think the key will be always, as we think about a larger deal, to make sure it's accretive near term in terms of the distributions to our shareholders as well as accretive, more longer-term in terms of the net asset value. And so really, again, when we think about these larger deals, it's being disciplined and making sure in our underwriting that we'll experience accretion both short term and longer term because we are aware with the expectations relative to the 113 net undeveloped locations that we have out there to be drilled for us over time, there is an implied growth in our portfolio. So we want any deal we do to make sure that there's associated growth that comes with it.

This concludes our question-and-answer session. I'd like to turn the conference back over to Mr. Rob Roosa for any closing remarks.

Now I appreciate everybody joining us this afternoon on the second quarter call. We look forward to reporting back to you in November with the third quarter results, and we'll speak with you then. Thanks a lot for joining again.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.