Black Stone Minerals LP (BSM) 2017 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Q3 2017 Black Stone Minerals LP Earnings Conference Call. (Operator Instructions) As a reminder, this conference call is being recorded.

I would now like to turn the conference over to Mr. Brent Collins, Vice President of Investor Relations. Sir, the podium is yours.

Thank you, Brian. Good morning to everyone, and thank you for joining us either by phone or online for Black Stone Minerals' Third Quarter 2017 Earnings Conference Call. Today's call is being recorded and will be available on our website along with the earnings release that was issued yesterday afternoon.

Before we start, I'd like to advise you that we will be making forward-looking statements during this call about our plans, expectations and assumptions regarding our future performance. These statements involve risks that may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements. For a discussion of these risks, you should refer to the cautionary information about forward-looking statements in our press release from yesterday and the Risk Factor section of our 10-Q, which will be filed later today.

We may refer to certain non-GAAP financial measures that we believe are useful in evaluating our performance. Reconciliation of those measures to the most directly comparable GAAP measures 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.

Company officials on the call this morning are Tom Carter, Chairman, President and CEO; Jeff Wood, Senior Vice President and CFO; Holbrook Dorn, Senior Vice President of Business Development; Brock Morris, Senior Vice President of Engineering and Geology; and Steve Putman, Senior Vice President and General Counsel.

I'll now turn the call over to Tom.

Thanks, Brent. Morning. Thank you all for joining us today. Black Stone had a solid third quarter of 2017. Production averaged 37,000 Boe per day for the quarter, which is essentially flat to the second quarter of 2017 despite some production shut-ins resulting from Hurricane Harvey. Despite those shut-ins, we grew our mineral and royalty volumes on a sequential basis. We averaged 75 gross well additions per month in the third quarter, and our year-to-date average would suggest that we'll have slightly over 900 gross well adds in 2017.

From a net revenue interest perspective, the additions were led by the Permian basin, followed by Bakken/Three Forks, Haynesville/Bossier and the Eagle Ford. Those 4 assets together accounted for approximately 70% of our net revenue interest adds in the quarter.

Looking ahead, we're very encouraged by what we have been seeing from a permitting standpoint across our acreage. By our estimates, as of September 30, approximately 15,000 horizontal well permits have been filed in the lower 48 in the preceding 12 months. That number has been steadily increasing through 2017 on a trailing 12-month basis. We estimated that as of the same date, approximately 8% of all of those permits involved BSMC acreage, which is a pretty remarkable statistic for a mineral and royalty owner.

Lease bonus and other income for the quarter was $12 million and was mainly driven by leasing in the Delaware Basin. We've had a very good year with respect to lease bonus, which is a tribute to both the strength of our acreage position and to the great work of our land team, which does an outstanding job of promoting our acreage to operators. For the first 9 months of the year, we recorded $37.1 million compared to $26.1 million for the same period in 2016. In 2017, we have generated lease bonus in well-known resource place as well as place that are off the beaten track.

On the acquisition front, we closed about $36 million of acquisitions during the quarter, $14 million of which was done with direct equity to the sellers. Substantially, all of the acquisitions in the quarter were bolt ons to our core Shelby Trough acreage. We're very excited about how we are positioned in the Haynesville and Bossier development in East Texas. We've increased our net mineral acreage position in the Shelby Trough by approximately 38,000 acres so far this year, and we have 2 active well-capitalized operators developing our mineral position. Year-to-date, we have closed over $160 million of acquisitions concentrated in the Midland and Delaware Basins and Haynesville/Bossier.

Our assets are performing well, and we've had a good year thus far. We are seeing strong producer activity in our core basins, and have meaningful acreage positions in several areas where operators are drilling wells that could open up new development and provide further production growth for us in the future. I think we're very well positioned going forward.

With that, I'll turn the call over to Jeff to review the quarter.

Thank you, Tom, and good morning, everyone. So we posted another solid quarter, and that's across all of our key metrics. As Tom mentioned, we reported average daily production for the third quarter of 37,000 Boe per day, and that's essentially flat with reported second quarter volumes.

Our royalty volumes grew slightly, and our working interest volumes were down about 3% from the record high we reported last quarter. We estimate the third quarter production was negatively impacted by approximately 500 Boe per day as a result of Hurricane Harvey, but to our knowledge, all of our operators in those affected areas are now back to normal operations. Between the impact from Harvey and some revised completion timing estimates from our primary operator in the Shelby Trough, we now expect to come in at or just below the low end of our revised production guidance of 37,000 to 38,000 Boe per day for the full year. With our high royalty and working interest that we have in the XTO development area in East Texas, changing in their completion schedules can shift volumes across quarters, and that's what's happening here. I will note that we view this only as a timing issue, and we remain very encouraged by the XTO's great progress and its plans for continued development in that area.

Turning to our financial results. Lease bonus and other income was $12 million for the third quarter and was driven primarily by leasing activity in the Delaware. Through September 30, we recorded over $37 million of lease bonus, which puts us above the high-end of our guidance for the year. The specific timing of lease bonus is a bit hard to predict by quarter, so we're going to stay on the conservative side now and just say that we expect lease bonus to come in north of $40 million for the full year.

I made this point last quarter, but I think it's worth saying again, the fact that a significant amount of our portfolio is unleased is an underappreciated asset of Black Stone. The lease bonus we receive, and then the new production that follows is equivalent to small acquisitions, with the important distinction, of course, that we don't pay anything for those. We liken those to unleased asset -- we liken our unleased assets to embedded cost free dropdowns, and they are present throughout our asset portfolio.

Moving on, we realized a $5 million cash gain from hedge settlements during the quarter. We have a solid hedge book, with about 90% of gas and 80% of oil hedged for the fourth quarter of '17. In 2018, we have hedges in place that cover approximately 80% of expected gas and 90% of expected oil.

Yesterday, we layered on an initial 2019 hedge position, and we now have approximately 20% of our expected oil and gas volumes hedged for that period. As I'll discuss in a moment, we've added some flexibility through our amended credit facility, which allows for greater volumes and tenor in our hedge program, and we've already started to take advantage of that.

LOE increased in the third quarter of '17 to $4.6 million. That's up from $4.1 million in the second quarter. LOE per working interest barrel was $3.19 in the third quarter, and that, again, increased from $2.83 in the second quarter. That increase is a result of higher levels of workover activity that's being built to us by our operators.

Total G&A was down slightly in the third quarter to $17.3 million. Cash G&A has been trending down throughout the year as transaction-related expenses associated with this year's acquisitions were largely incurred in the first half of the year. We can see some variability in the noncash portion of our G&A, since changes in our common unit price impact the accounting value of certain of our outstanding equity awards. We saw that in this past third quarter is -- the 10% move up in our unit price resulted in the recognition of some additional noncash G&A expense in the quarter.

Overall, as I said, a very solid quarter with adjusted EBITDA at $77.7 million and distributable cash flow at $69.1 million, both of those up from last quarter.

Yesterday, we announced our distributions attributable to the third quarter of '17. Common unitholders' will receive $0.3125 per unit or $1.25 per unit on an annualized basis, and subordinate unit holders will receive $0.20875 per unit.

Distribution coverage for the third quarter remained very strong at 1.3x on all units and at 2.1x just considering our common units. As we have discussed previously, in determining the amount of distributions to both common and sub holders, our board looks at a number of factors, including our distribution coverage and our distribution coverage after deducting our net working interest capital expenditures. Our goal as we talked about over the long term is to fund working interest CapEx with retained cash flow, although that may vary in certain quarters where that CapEx is particularly light or heavy.

Our net working interest CapEx for the third quarter was $1.8 million, and that in part was due to the timing of some CapEx covered under our farmout agreement with Canaan Resource Partners.

With that, DCF after networking capital expenditures for the quarter was $67.3 million, and our coverage after deducting working interest CapEx was 1.3x.

Staying with CapEx, we now expect that total CapEx for the year will come in between $50 million and $60 million. That is up slightly from our previous guidance. One reason for this is that, we intend to drill a well this quarter in a new prospect area that we're excited about, and the rest of the increase is driven by timing of operator schedules, in particularly in East Texas.

Activity there has outpaced our original expectations, especially as our second major operator in the Shelby Trough has started to gear up development. We have retained a working interest across all of that development area, and are engaged now in ways to monetize those interests, similar to what we did with the farmout of our working interest in the XTO-operated wells earlier this year. With that, we should be in a position to drive our working interest CapEx to de minimus levels by mid next year.

Turning to the balance sheet. Financially, we are in great shape. As of the end of the third quarter we had $362 million of debt outstanding, and our debt to trailing 12-month EBITDAX is 1.3x, and that's down from last quarter. We had almost $200 million of liquidity available to us at quarter end, and that has continued to improve since that time. As of yesterday, total debt was down to $332 million.

Subsequent to quarter end, the borrowing base on our revolver was reconfirmed at $550 million, and on November 1, we closed on an amended credit facility with our existing bank group that extends our maturity until November of 2022, and also provides additional hedging capacity, and there's no change in our pricing grid or total commitments with that amendment.

As you'll remember, in the second quarter we set up an aftermarket equity program. During the third quarter, we sold about 1.8 million common units and received total proceeds from that ATM in the quarter of about $30 million, which supported our acquisition efforts while maintaining the strong liquidity under our revolver. I will note that we don't expect our ATM usage to be this significant in the regular course of business, as proceeds in the third quarter were for a combination of both regular way sales, and we saw some larger block trades.

With that, Brian, I will turn the call over to questions.

(Operator Instructions) Our first question comes from the line of Nick Raza from Citi.

Just really quick. Could you just talk about the macro sort of view about just purchasing royalty interest in other regions besides the Permian's, particularly around maybe the Marcellus, the Utica, sort of the Appalachian region or maybe the Bakken for that matter?

Nick, this is Holbrook. The Permian is a -- there's a lot of capital that's flown into that space, and so it is very expensive. And we are seeing opportunities in lots of other plays across the lower 48. I think our Shelby Trough activity is evidence of that, where we've acquired approximately 38,000 net mineral acres for prices that we think are fairly compelling, especially when you consider the risk reward versus plays like the Delaware and the Midland that are more pricey and more front page news.

Okay. And there, do you sort of have a view on acreage up in the Northeast, which is -- obviously, you know, production seems to be ramping up there as well?

We've always liked Appalachian and the Marcellus and the Utica place up there. We have a small position up there. We'd love to add to it. We've -- it's just always been a challenge trying to really get in front of where bases is going out there. And we'll see, as more pipes come on and that story cleans itself up, it may be easier to price those assets.

Got you. And then, I guess the other question I had really quickly was, in terms of just your gas price realized. Understanding that you might not have a lot of clarity on the NGL component or the Btu component. I mean how should we go about thinking about that for just modeling purposes and forecasting?

This is Brock Morris. Just thinking about where our future production's coming from, a lot of our growth is going to be out of the Haynesville, which is not going to have any liquids to speak off. So in general, I might expect the benefit of the NGLs and our gas price to be a smaller part of our production mix going forward.

Yes. But Nick, the nice thing, of course, of that is that we see relatively low differentials out of that East Texas production, just given how close we are to hut, so -- and the vast majority of that growth will be royalty production, which does not bear any transportation costs.

(Operator Instructions) Our next question comes from the line of [Bran Sekoches] from Raymond James.

Just in relation to the amended credit facility to securities, what's kind of the additional hedging capacity that was provided by that amendment?

So previously, Brent, we were restricted to really PDP volumes, and so we've added a component here that enables us to hedge greater volumes because it's a test. It looks at the past 3 months of our production, and then also what our future forecasted production, and then we've got to reduce that by certain percentages going forward. So it just enables us to have greater flexibility over the next 2 years to hedge greater volumes if we want to. And probably, equally importantly, it enables us to look out further in our hedging program than we've been able to with the strict PDP constraints under the prior version of the facility. So we will get that out. You can see it. But it's basically kind of 90% for a couple of years of either backward looking 3 months production or our expected production, and then that 90% ramps down to 70% and 50% as we go further out in time.

Okay. That's helpful. And forgive me, if this is -- I don't see any slides right now. But can you give us a sense of what kind of positions you're taking on for the next few years? Is it just swaps, colors, what kind of things you're looking at?

Yes, so historically, we've looked to be kind of 75-ish percent hedge in the near term and maybe 50% of expected volumes as we look out in the 12 to 24 months timeframe, and we remain pretty consistent. With that, we'll file our Q later today. It'll have the detail of those hedging positions. But so far we've remained pretty consistent. As I said, we put on positions covering about 20% of '19. Those were just yesterday, and those were the first positions we've added for '19. And then higher percentages for '17 and '18. And then, in terms of the method by which we hedge to date, everything in the entire book has just been swaps.

Okay. Okay, great. That's helpful. And then just one last question. Related to the lease bonus, just curious what's -- what is it that actually drives the lease bonus numbers? Is that just negotiations with the lessee? Or is there -- is it just on a case-by-case basis?

This is Holbrook. It is negotiations with the lessees. When we have acreage in a competitive area that multiple parties are trying to lease, we try and run as competitive as a process as possible. In other areas that may be less active, sometimes you just have to take what the market is offering, because there may only be 1 or 2 active operators in a given county.

Okay. Fair enough. And then, I guess just a follow-up on that is, in 3Q, you guys mentioned the activity was primarily in the Delaware Basin, whereas, last quarter, I think you mentioned 3 areas: the Bakken, the Permian, and the Austin Chalk. Is there a specific area that we should think about as being the target for 4Q? Or is it primarily going to be in that Delaware Basin area?

4Q, I think we're working on a number of traits right now. There could be some Delaware activity, there could also be some Austin Chalk activity and frankly, there could be some step up in the Panhandle. And I think -- you know, we have an $18 million gross acre position, with over 7 million net acres. So we move a tremendous amount of land paperwork through this office on any given day. So we love it when we have a bunch of different plays pop up from a lease bonus perspective.

(Operator Instructions) Our next question comes from the line of Peter [Big] from Ragnarok Capital.

You guys announced earlier this year that you had executed a series of leases in the Haynesville. I think all of those leases carried multiwell obligations per year. My question is, how many wells have been drilled under those leases? And second, given that volumes were pretty flat in the quarter, is there an inventory, if you would, of docks out there that are going to be completed later on this year or early '19?

Peter, Brock Morris. So we had 2 wells which were drilled prior to what we talked about earlier this year. Since then, 4 wells have been drilled and completions on those are underway, and 3 more are currently drilling.

Okay, all right. The other question I had, Tom, you kind of hinted around a new area or new well that you're excited about. By any chance, is this in the Wilcox play, which you own a big mineral spread in? Or could -- can you -- if it isn't there, can you comment where we might be talking about?

Yes, it is in the Wilcox. No, it hasn't been drilled yet. Yes, it's about to spurt. It is in the Wilcox.

And I am currently seeing no further questions, and I will now like to turn the call back to Tom Carter, President and CEO, for any further remarks.

Thank you all for joining us today, and we look forward to speaking with you next quarter.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program and you may all disconnect. Everyone, have a great day.