Black Stone Minerals LP (BSM) 2016 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Black Stone Minerals fourth-quarter and full-year 2016 earnings conference call.

(Operator Instructions)

As a reminder, this call is being recorded. I would now like to introduce your host for today's conference, Mr. Brent Collins, Vice President of Investor Relations. Sir, you may begin.

Thank you, Skyler, and good morning to everyone and thank you for joining us either by phone or online for Black Stone Minerals' fourth-quarter and full-year 2016 earnings conference call. Today's call is being recorded and will be available on our website along with the earnings release, which was issued yesterday afternoon.

Before we start, I'd like to advise you that we will be making forward-looking statements during this call about our plans, expectations, and assumptions regarding our future performance. These statements involve risks that may cause 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 section of our 10-K, which will be filed tomorrow. 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 will now turn the call over to Tom.

Good morning and thank you for joining us today. I'm going to cover some of the highlights for the year and discuss some items of strategic importance for the partnership and then I will turn it over to Jeff for financial review.

2016 was a good year for Blackstone. Production for the year came in at 31,700 BOE per day, which was an 11% increase over 2015 production levels. This was near the high end of our revised guidance of 31,000 BOE to 32,000 BOE per day for the year, and well above our original guidance. That translates to net income of $20.2 million and adjusted EBITDA of $262.3 million for the year, both of which were improvements over what we reported in 2015. We saw proved reserves grow to 63.4 million BOE, which represents a 27% increase over the prior year. The reserve of growth was driven in large part by the active development we saw in the East Texas Haynesville program this year. I am very pleased with how the partnership performed for the year, particularly when you consider the state of the industry a year ago when we were touching cyclical lows for commodity prices and the rig count.

Last year was an active year for acquisitions. We closed over $140 million in acquisitions in 2016, including a large diversified mineral package from Freeport-McMoRan and a great asset for Wattenberg Field and Colorado. We continue to be active in 2017 and have all ready closed on a total of $58 million of acquisitions to complement our existing core positions in the Delaware Basin and in the East Texas Haynesville Bossier play. One of those transactions the majority of the purchase price was paid with Black Stone units issued directly to the sellers. Having equity as a currency that provides sellers diversification and liquidity in a tax-efficient manner was one of the reasons we went public, and we expect this to be an important tool as we look at acquisitions going forward.

A week ago we announced that we entered into an agreement with Canaan Resource Partners to farm out 80% of our working interest for well spud after January 1, 2017, and 34,000 gross acres in Saint Augustine County, Texas that's being actively developed for the Haynesville and Bossier play. We had a 50% working interest in the area, which is unusual for us, and it has recently been the most significant area of our annual CapEx. We have been discussing ways to address our growing working interest volumes and associated capital for a while now, so we are excited to deliver on this commitment. The farmout agreement significantly reduces our overall capital obligations and brings in a strong financial partner to ensure the continued development of this important play in which we have a significant role.

Under the agreement we will retain and overriding royalty on the farmed-out interest that allows us to capture a meaningful percentage of the total profits of the wells. The transaction allows us to remain focused on our core of mineral and royalty business, highlights the value and opportunity we can derive through our participation in selected working interest programs, and increases our free cash flow available for distribution by reducing our working interest capital spend. With the farmout starting in 2018 we expect working interest volumes to start to decline. We have some initiatives in process that we think will backfill those volumes and drive continued production growth over long term while bringing our production mix into the targeted range of 80%-plus royalty volumes. We look forward to sharing more details with you on these initiatives in coming quarters.

Looking ahead to 2017, we expect that we will be able to grow production by approximately 14%. Our common distribution is scheduled to increase in the second quarter by approximately 9% to an annualized $1.25 per unit, and is scheduled to increase again in Q2 of 2018 to an annualized $1.35 per common unit. As you have heard before on these calls, we believe that a growing distribution is an important factor in setting the value of our common partnership units.

Recall that as part of our IPO in May 2015, we subordinated approximately half of the legacy ownership to provide the common unitholders a high degree of protection and certainty that their cash distributions would grow over time. We stuck with that commitment when commodity prices fell by reducing distributions to the sub, even as we increases distributions to the common holders. Management and the Board of Directors are determined to continue the growth of the common distributions as we exit the subordinated unit conversion test period in early 2019. We recognize that one of the factors that could affect this objective in addition to the actual distributable cash flow, is the impact of converting the subs and the number of total common units outstanding after conversion.

We are working hard to put ourselves in a position to be able to convert as much of the subordinated class as possible, and are sensitive to any contraction in ownership resulting from less than full conversion of the subordinated unitholders. However, our top priority is the long-term health of the partnership and we believe that the partnership is strengthened by growing common distribution over time. As a result, depending on commodity prices and other factors, the subs may need to convert at a ratio of less than one to one. Management and the Board have agreed that the decision around the conversion percentage will be made in the context of positioning the common units for continued distribution growth.

With that, I will turn the call over to Jeff for review of the quarter.

Okay; thanks, Tom, and good morning everyone.

Yesterday we put out our results for the fourth quarter and full year of 2016 as well as our guidance for 2017. Our reported production in the fourth quarter was just shy of 30,000 BOE per day. That is below the 33,000 run rate that we had discussed on the last call, and frankly it's a production level that we don't believe reflects the ongoing strength of our underlying business. For the fourth quarter was negatively impacted by a couple of items. First, in the East Texas Haynesville Bossier play, volumes were down because of shut-ins of existing production, while XTO, who is was one of our major operators in that area, completed new wells on adjacent acreage. Over the longer term, of course, this is great news, as it demonstrates a high level of activity in the area and points to future production growth for us. We believe the impact of this was around 1,000 BOE per day for the quarter.

We also had a number of one-time adjustments, which lowered reported volumes for the quarter. Both of these items also have corresponding impacts to our reported adjusted EBITDA and our distributable cash flow. As we pointed out in the earnings release last night, we believe we exited the year at around 31,500 BOE per day despite ongoing volumes deferred through those shut-ins.

Looking into 2017 production, we expect that we are going to be on a generally inclining production trajectory throughout the year, with the first quarter being in that area of 33,000 per day run rate that we have been operating at for the last couple of quarters. We expect 2017 oil production is going to be relatively flat throughout the year, and we are expecting substantial increases in gas production; and that is driven by both royalty and working interest volumes. As a reminder, the farmout agreement that Tom discuss only covers wells spud in 2017 forward, so we expect to continue to see working interest volumes increase due to Haynesville and Bossier wells completed in late 2016 and early 2017.

Our realized prices for the fourth quarter, excluding the impact of derivatives, were $45.43 per barrel for oil and $3.23 per Mcf for gas. Overall our realizations were in line with last quarter. For 2017 we think we will continue to see realization percentages for oil in the low 90s and for gas we expect a premium realizations we have seen historically will start to decline through 2017 as dry gas from the Haynesville becomes a larger portion of our gas mix. We reported a hedging loss of $24.2 million for the fourth quarter, and that consisted of a $5.6 million cash gain, primarily related to oil settlement, and a $29.8 million non-cash loss that reflected positive moves in the forward commodity curve between quarters. We have added hedges recently and our hedge book now covers 65% of expected 2017 oil production and about 75% of expected 2017 gas production. We have also locked in initial hedge positions for 2018; and we will file our 10-K tomorrow, and that will have a lot of detail around these hedge positions if you would like to see further information.

Lease bonus about $6 million for the fourth quarter, with most of that activity in the mid-continent and focused on the Stack and Woodford play. For the year, lease bonus came in at $32 million and we expect a similar amount in 2017. The midpoint of our guidance is right there at $30 million. Moving on to costs, LOE for the quarter was $4.35 per working interest DOE. For the year, we came in at $4.62 and that is below the low end of our guidance range. The big driver on this lower per unit cost is the growth in our Haynesville working interest volumes, as well as lower service costs and reduced workovers. We think these per-unit rates will actually continue to decline through the first half of 2017. For the full year of 2017 we expect to be in the $18 million to $22 million range for LOE. Production costs and ad valorem taxes were up in the quarter due to higher prices, as well as to some adjustments that we made in the fourth quarter and are assumed rates for deducts and for severance taxes. Overall, for 2016 we came in a little over 13% of total oil and gas revenues, and we've got it to a range of 13% to 15% for 2017.

G&A for the quarter came in at $20.9 million, and that caused above our full-year guidance for G&A for 2016. For the fourth quarter was high for a few reasons: first, we performed really well against our goals for the full year, and that resulted in an increase in our short-term incentive comp, and all of that was trued up in the fourth quarter. Second, we had some additional expenses related to employees transitioning in and out of the company. And lastly, we had some transaction-related costs that hit in the fourth quarter, including some related to the farmout agreement. For 2017 we expect the first quarter to remain a bit high at approximately $20 million, due in part to the closing of the farmout agreement and the several acquisitions that Tom mentioned. We expect it to drop to more moderate levels thereafter, and to total between $66 million and $70 million for the year. G&A came right in the middle of our range for 2016 and we are expecting basically the same range for 2017.

Last items on the income statement: net loss for the quarter came in at $7.3 million, adjusted EBITDA was $58.3 million, and cash available for distribution came in at $50 million. Yesterday we paid ourr distribution to common unitholders for the fourth quarter of $1.15 per unit on an annualized basis. Even with the shut-ins and one-time items in the quarter, our distribution coverage was 1.1 times on all units and 1.8 times on our common units. For the full year 2016 we had coverage of 1.3 times on all of our units and 2.2 times on the common.

Finally, our balance sheet remains strong, and with the format agreement in place we expect our working interest CapEx for 2017 to decline to $50 million to $60 million, and $40 million of that relates to well commitments we made in 2016. We ended the quarter with $316 million drawn on the revolver, relative to our borrowing base of $500 million. Our debt to trailing EBITDAX to year-end was around 1.25 times versus the max of 3.5 times that allowed in our credit facility. As of yesterday the drawn balance on the facility was $394 million, and that is after the acquisitions we made in 2017 and the payment of our fourth-quarter distribution.

And with that I will turn the call over to questions.

(Operator Instructions)

Our first question comes from Chad Mabry with FBR Capital. Your line is now open.

Thank you. I had a question on the 2017 CapEx Budget. It sounds like the majority of your working interest program is going to the Haynesville for completion. Is it safe to assume that CapEx is weighted towards the first half of the year? I'm just curious how that production cadence should look this year.

Yes. This is Brock Morris. That is correct. About $40 million, as Jeff mentioned, is related to wells that were actually started last year and those completions will take place and 70% of the cost of these wells is in the completions and those completions will take place in the first part of this year. And we had a much higher interest in those wells [of] the pre-farmout. So I would expect that the capital, yes, is going to be pretty front end weighted.

Okay. And can you provide any color on where that gets you on an exit rate for 2017 production?

Yes, I think -- Chad this is Jeff, we are probably going to need to stick to our production guidance of [35 MBoe/d to 37 Mboe/d] for the year and as I mentioned in my comments we do expect the first quarter will probably be in that [33 Mboe/d] range that we have been at for the past couple and then we expect it to generally inclined through the year. So hopefully that gives you enough color on what we think that comes down.

That makes sense. I will get back in queue. Thank you.

Thanks.

Our next question comes from Kashy Harrison with Simmons Piper your line is now open.

All right good morning, everyone, and thanks for taking my questions. So over the past two years production has largely exceeded Street expectations since you guys went public. Any thoughts on how we should -- for modeling purposes think about multi-year production growth especially in light of the recent farmout agreement. Should be thinking of moving forward just for our models, low single digits, mid-single digits, high single digits? Just any guidance would be really appreciated.

This is Jeff. Look, as Tom mentioned, in his remarks we've got a number of things in the works that we are pretty excited about that we will talk about in future quarters. There is no doubt that as we look into 2018 and 2019 that working interest program, farming that out working interest production by design is not going to be as robust, obviously, as it would have been had we fully participated. Again we think the trade-offs for that are well worth making so that was a very conscious decision.

We expect to deliver in terms of production growth which leads to then of course cash flow growth and long-term distribution growth I would say we're targeting in the mid single-digit range. Over the longer term.

Excellent. Thank you. And I really appreciate the [prudence] and the color on the conversion of these subordinated units. And I guess this kind of links into the last question but, as you think about the long-term growth trajectory of distributions in discussions with the board beyond 2019, do you think you are going to maybe set another MQD or do you think you will move to a business model where the distributions will be set on an annualized basis based on your expectations of future net cash flow growth?

This is Tom. Let me take a shot at that one. As we said, we think it is very important to continue to see growth in our common distribution. We will exit -- we will exit the subordination cycle at $1.35 per common unit. And so we expect to continue to grow that common distribution into the future. I mean that is obviously our business model. And we expect to have -- we are shooting for total returns in the low teens.

So continuing to increase the common distribution is important. We think we can deliver on that. We don't have a plan right now to fix, per se, a common distribution, but historically, we have set our distributions and stuck with them. And they have generally increased over time. The only time our distribution has actually decreased was in one quarter back at the time of the great recession and that was out of an abundance of caution of not really going where the world was going. So I hope that answers that.

That is very helpful. Thank you very much for that. And then one last one for me, maybe for Jeff, with the borrowing base redetermination coming up should we be expecting an increase with the positive reserve revisions and better pricing? Is that fair?

That is to be determined. The redetermination is coming in April. I think what you can assume is as you saw in the release we posted really strong gains in our proved reserves over last year so that is definitely a helpful factor. Gas prices have been a little challenging of late so we have not seen where the banks are going to come out with the new price decks so we will probably have to put a pin in that for now but overall I think we are relatively comfortable with our liquidity position and any potential increase to the borrowing base if it comes adds to that.

Thank you, that's it for me.

Thanks.

Our next question is from Anthony Diaz with Raymond James. Your line is now open.

Hi guys, thanks for taking my question. I have a couple of things. First off, I understand the gas impact from the Haynesville shut ins in 4Q but we all saw oil come off pretty substantially. Is there a specific reason we can point to for this -- lack of development, lack of much production? And [ILC] going forward into 2017 we see that oil mix falling off even further. Is there anything you guys can point to specifically for this or is this just increased gas volumes? What are you guys thinking?

Yes, Anthony this is Jeff. I will start with the quarter over quarter on the oil. I mentioned in my remarks that we had what we consider one-time adjustments in the quarter which were largely related to oil volumes. There are times where we get updated information from producers which causes us to adjust our estimates. In the third quarter we had a few of those that sort of went our way. In the fourth quarter those seem to all move against us. And again, most of that was in oil volumes. As we look forward into 2017 I think what you are seeing is what we expect to be really substantial growth in gas volumes that is changing that product mix.

Okay. That's fair. And then my next question is just regarding the Delaware acquisition. Are there any specs you guys can give us on that where exactly this asset is? Is it picking up more interest in your existing footprint? [Is there] current production associated with this [clutch book] on the asset operator exposure and things like that?

There are two acquisitions out there. One was increasing our interest under an existing footprint and that position is more central Loving operated by Anadarko primarily, a little bit of EOG and a little bit of Tema. The other one is under the RSP position; that was a new footprint we have added. This is Holbrook Dorn by the way. And both of those we think our accretive to 2017 guidance.

Great. Awesome. I appreciate the color. I will drop back in.

Our next question is from Nick Raza, Citigroup. Your line is now open.

Thanks guys. Just a couple of add-ons. In terms of the outage, the shut-in, you mentioned that it was because of a processing facility being down in Haynesville. Can you tell us which one that was?

Yes, this is Brock Morris. Really there was a minor shut-in related to just annual maintenance in the local area [dehy] facility. But the shut-ins were largely driven by offset activities on -- XTO is doing pad drilling and they have to shut in wells while drilling other wells on those pads and then during frac jobs we shut-in wells some distance away from the wells being fracked. It was just a lot of that they came in the fourth quarter -- we knew that there was going to be an impact during 2016 and all of that came in the fourth quarter. So it's really nothing more than that. It was operations as usual when you've got a pad drilling operation like that.

Yes Nick, this is Jeff. You never love to see deferred volumes. I you're going to see them deferred this is the reason you want, right? Drilling activity is really increasing and it is mostly completion of offsetting acreage that is driving those temporary shut-ins. The other thing that I would note is that we have -- in extensive discussions with XTO we have baked the impact of future additional production related shut-ins or completion related shut-ins into our 2017 guidance.

Okay. Fair enough. And then just turning to the farmout. How accretive was that from a production standpoint? Is it just net even to you guys or will you lose a little bit of production as a result?

The answer to that is when you farmout a 40% working interest with a probably -- with a 20% royalty on it, you have a lot less net revenue points. So theoretically and in reality at some point your volumes go down. However, as we mentioned we have several initiatives in progress where we expect to substantially replace and maybe increase over time the net revenue from that area by replacing some of those working interest volumes with increased royalty and overriding royalty interest that have a lot less CapEx and a lot less LOE and therefore more free cash flow.

We will see an effect of that change for a period of time. But the long term we continue to see growth -- good growth in that whole trend.

Okay. Got you.

I would just add for a mineral company, as I said in my remarks, a 50% working interest is an anomalously large interest for us. And just a little color on that, we pick that interest up in 2014, 2015 when Encana exited that area. And our operator asked us to partner up with them on a 50-50 basis.

At that point in time that play had a lot of question marks around it. There were some small handful of wells that had been drilled and the completion techniques et cetera in the cost structure were not really known. And so we agreed to partner with them at that level with the hope that with XTO's expertise that area would turn into a very positive development area for our royalty interests.

So we made it anomalous decision. We knew at the time that if it was successful we would have to monetize that interest because we are not going to become an upstream working interest MLP. So it is a good news good news story. It did work out very well. And they are drilling 14 wells to 15 wells per year versus one well to two wells That program was accelerating at a rapid place and we have taken the step to rebalance our portfolio up there to a royalty portfolio and move forward.

That's great color, thanks. Is there opportunities to do more of this for your remaining working interest or is this a one-off deal?

I would tell you that there are numerous opportunities for us to continue to do this. And we typically in large trend plays where we have a large mineral interest, we retain the right to participate. Historically, not all of those plays turn into big development programs and that is just the way the oil and gas business is. But when they do, it creates a lot of running room for those working interest options and we look at that as a way to monetize these things when they are of size so that we can increase our net royalty and overriding royalty exposure to them.

Got you. Got you.

There are numerous plays where we see that happening in the future.

Fair enough. And then just a little bit more of a question about your borrowing base. In terms of hedging out your remaining production, do you intend to do that before April 2017 when you go back for redetermination? Or how should we think about that in terms of a percentage? Is it going to be 90% hedged by the time you speak to your banks?

No. We are pretty well hedged on available volumes already. You will see in the K that we will file tomorrow we will give you the hedge detail but we've hedged up a lot of volumes. We don't really do that specifically for the redetermination. It is just a common practice that as new volumes come online we obviously can only hedge our PDP expectation so as those come online we typically look to lock those in. So it is not a borrowing base centric decision, it's something we prudently do from time to time as new volumes come on.

Okay. Thanks guys. I will get back in line, thank you.

Thanks, Nick.

(Operator Instructions)

Our next question comes from Brian Brungardt with Stifel your line is now open.

Yes, thanks for taking my question. I appreciate the color on the previous questions. So realize the lease bonus outlook is in line with your historical numbers there, but given the recent improvement in commodity prices and general uptick in producer activity is the 2017 guidance baking in a degree of conservatism or does that include more of what you're seeing in the field?

This is Holbrook Dorn. I would argue that the 2017 guidance bakes in some uncertainty surrounding the current commodity price environment. And there is a lot of positive things out there on oil and there were some on gas and so it is hard to say where exploration budgets are going to shakeout as the year progresses. It feels like February 2016 is long behind us. But we are just being cautious there. If the environment continues to improve we would hope that our guidance proves to be conservative but time will tell.

Got you. That's all I have. Thank you.

Thanks, Brian.

We have a follow-up question from Nick Raza, Citigroup. Your line is now open.

Thank you. Sorry guys, just a quick additional question. In terms of the expenses -- excuse me, in the last quarter of 2016 were there any transaction expenses related to any of the acquisitions that occurred last quarter?

Right. So the uptick in G&A --there is a number of things. There were absolutely some transaction-related expenses including related to the farmout. As I mentioned, we did have -- G&A was up in addition because of some higher short-term comp for the year resulting from us exceeding our budget forecast for the year. And then we did have some executive costs from some of the transitions in and out during the quarter. So those were the three drivers of G&A being a little bit elevated in the fourth quarter.

Okay, fair enough. And back to the question on the lease bonus. It seems like the lease bonus was about $6 million versus $7 million last year same period. Is there any discounting that is being done to incentivize the operators to pick up the acreage? I will just follow up, the reason I ask is the same reason I always ask which is it is very hard to determine the what that number is going forward.

No, I appreciate that. I would say that we are very thoughtful about what the marketplace is. We are also thoughtful about balancing upfront cash versus driving near-term development. We look at each trade independently and what we think is the best approach on it. If we think a certain position has lower risk from a development perspective and it can be additive to volumes in the near-term we may discount the upfront cash we would want on that lease in exchange for increased near-term development. And vice versa we think it is fairly exploratory and were not quite sure how that play is going to work out, we may want to maximize upfront cash.

Got you.

And I would just add to that, as part of these discussions around the farmout and Haynesville volumes we look forward to more discussion in the future as some of this rolls out. But we are optimistic that our rig count and drilling and development in that area is going to see a meaningful uptick based on some of these initiatives we have put in place that are bringing rigs in on a continual basis in lieu of upfront bonus money.

Got you. Thanks guys. I appreciate the color.

Thanks.

At this time I'm showing no further questions. I would like to turn the call back over to Mr. Tom Carter, Chairman, President, and CEO for closing remarks.

Well thanks everybody for joining us today. And we hope you got the information you needed through this call and we look forward to speaking with you next quarter.

Ladies and gentlemen, thank you for your participation in today's conference. You may now disconnect. Everyone have a great day.