Good day, ladies and gentlemen. And welcome to the Black Stone Minerals’ Fourth Quarter and Full Year 2016 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time. [Operator Instructions] As a reminder, this conference 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. 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'll turn the call over to Tom.

Good morning and thank you for joining us today. I am going to cover some of the highlights for the year and discuss some items of strategic importance for the Partnership. And then I'll turn it over to Jeff for financial review. 2016 was a good year for Black Stone. Production for the year came in at 31.7000 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 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 reserve grow 63.4 Boe which represents a 27% over the prior year; the reserve of growth was driven in large part by the active development we saw in 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 2016 including a large diversified mineral packet from -McMoRan in great asset in Wattenberg Field in Colorado. We continued to be active in 2017 and have already closed on a total of $58 million of acquisition that compliment our existing core positions in a Delaware basin and in the East Texas Haynesville/Bossier play. And one of those trends actions and majority of the purchase price was paid with Black Stone units issued directly to the sellers. Having equity as a currency that provides seller's diversification and liquidity in a…

Okay. Thanks, Tom and good morning, everyone. Yesterday we put out 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 33,000 Boe per day. That's below the 33,000 run rate that we've discussed on our last call and frankly it's a production level that we don't believe reflects the ongoing strength of our underlying business. So 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 one of our major operators in that area completed new well on adjacent acreage. Over a longer term of course this is great news as it demonstrates the high level of activity in the area and points the future production growth for us. We believe the impact of this was around a 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 had 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 firs quarter being in that area of 33,000 a day run rate that we've been operating at the last couple of quarters. We expect 2017 oil productions is going to relatively flat throughout the year and we are expecting substantial increases in gas production and that's driven by both…

[Operator Instructions] And 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 our CapEx is weighted towards the first half of the year? Just curious how that production cadence should look this year.

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

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

Yes. I think Chad this is Jeff. I think we are probably going either stick to our production guidance of $35 million to $37 million for the year and as I mentioned in my comments we do expect that first quarter probably be in that $33 million range that we've been at for the past couple and then we expected to generally incline through the year. So hopefully that gives you enough color on where we think that comes out.

And our next question comes from Kashy Harrison with Simmons Piper. Your line is now open

Hi, good morning, everyone. And thanks for taking my questions. So over the past two years production has largely exceeded read expectations since you guys went public. Any thoughts on how we should just from a lay purposes just think about multiyear production growth especially in light of the recent farmout agreement. Should we be thinking hey moving forward just for our models low single digit, mid single digit, high single digit. Is just any guidance would be really appreciated?

Kashy, this is Jeff. I mean look we as Tom mentioned in his remarks we got a number of things in the work that we are pretty excited about it, that we will talk about in future quarters. There is no doubt that as we look into 2018 and 2019, that working interest program forming that out in the 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. What 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 are targeting in that mid single digit range over the longer term.

Excellent, thank you. And really appreciate the prudence and the color on the conversion of these subordinated units. And so I guess this kind of links in to the last question but as you think about the long-term growth trajectory of distribution and the 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?

Hi, this is Tom. Let me take a shot at that one. As we said, we think it's very important to continue to see growth in our common distribution. We will exit the subordination cycle at a $1.35 per common unit. And so we expect to continue to grow that common distribution into the future. I mean that's obviously our business model. And we expect to have a total -- 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. And 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 are generally increased over time. The only time our distribution is 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 knowing really where the world was going. So I hope that answers that.

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

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

And our next question is from Anthony Dye 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 also oil come up pretty substantially. Is there specific reason we can point to for this? Lack of development, lack of cost production and then I'll see going forward in 2017, we see that oil mix kind of falling off even further. Is there anything you guys can point to specifically for this or is it just increased gas volumes? What are you guys thinking?

Anthony, this is Jeff. I'll start with just kind of a quarter-over-quarter on the oil. I mentioned in my remarks that we had some sort of what we consider one time adjustments in the quarter largely related to oil volumes and they are just times where we get some updated information from producers which causes us to adjust our estimate. In the third quarter we had a few of those to sort of win our way. In the fourth quarter those seemed to all move against us and again most of that was in oil volume. As we look forward in to 2017 I think what you are saying is just where we expect to be really substantial growth in gas volumes that's changing that product mix of it.

Okay. That's fair. And then my next question is just regarding the Delaware acquisition. Are there any facts you guys can give us on that where exactly this asset is? Is it picking up more interest in your existing footprint? Is a current production associated with this spud on the asset operator exposure 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 little bit of EOG and little bit [Tima], the other one is under the RSP position that was a new footprint we've added and this is Holbrook doing by the way. And both of those we think are accretive to 2017 guidance.

And our next question is Nick Raza with Citigroup. Your line is open.

Thanks guys. Just a couple of add on. So in terms of the average shut-ins you mentioned that it was because of a processing facility being down in Haynesville. Could you tell us which one that was?

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

Yes, Nick. This is Jeff. I mean while you always you never love to see to deferred volume, if you are going to see them deferred this is the reason you want right that drilling activity is really increasing and it is mostly just completion of offsetting acreage that's 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 way to 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 a bit of production as a result?

The answer to that is when you farmout 40% working interest with a probably with a 20% royalty on it. You have a lot less net revenue point. 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 may be increase over time the net revenue from that area by replacing some of those working interest volumes with increased royalty and overwriting royalty interest that have a lot less CapEx and a lot less LOE and therefore more free cash flow. So 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. And then --

And I would just add for a mineral company as I said in my remarks, a 50% working interest is really is anomalously large interest for us and just a little color on that. We pick that interest up in 2014-15 when it Canaan 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 questions mark around it. There were some small handful of wells that have been drilled and the completion techniques et cetera and 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 royalty interest. So we made an anomalous decision, we knew at the time that if it was successful, we would have to monetize that interest because we aren't going to become an upstream working interest LMP. So it's a good news story, it did work out very well and the drilling 14 to 15 wells a year out there versus 1 to 2 and so we've -- that program was accelerating at a rapid pace and so we've taken the step to rebalance our portfolio there to a royalty portfolio and move forward.

That's great color, Tom. Thanks. Is there opportunity to do more of this for your remaining working interest? Or is this sort of 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's just kind of 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 outsized so that we can increase our net royalty and overwriting royalty exposure there.

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 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 re-determination or I mean how should we think about that in terms of a percentage? Is it going to be like 90% hedge by the time you speak to your banks?

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

[Operator Instructions] And our next question comes from Brian Brungardt with Stifel. Your line is now open.

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

This is Holbrook Dorn. I would argue that the 2017 guidance bakes in some uncertainties surrounding the current commodity pricing environment. And there is a lot of positive things out there on well and there were some on gas and it's just hard to say where exploration budgets are going to shake out as the year progresses. Fields wide, February of 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 the time will tell.

And we have a follow up question from Nick Raza with Citigroup. Your line is now open.

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

Right. So that the uptick in G&A was -- so there were number of things. So 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 kind of exceeding our budget forecast for the year. And then we did have some kind of executive cost and some of the transition in and out during the quarter. So those were -- those are kind of three drivers of G&A being a little bit elevated in the fourth quarter.

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

Yes, no, I appreciate that. Listen, I would say that we are very thoughtful about what the market place is and we are also thoughtful about balancing upfront cash versus driving near term development. And we look at each trade independently and what we think is the best approach on it. We think a certain position has lower risk for development perspective and it can be added to volumes in the near term we may discount the upfront cash, we would want on that lease and exchange for increased near term development. Vice versa everything is fairly exploratory and we are not quite sure how that plays going to work out. We may want to maximize upfront gas.

Got you.

And I would just add to that we as part of these discussions around the farmout and Haynesville volumes, we look forward to more discussions in the future as some of these 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 put in place that are bringing rigs and on a continue basis in lieu of upfront bonus money.

At this time, I am 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 participation in today's conference. This does conclude the program. You may now disconnect. Everyone have a great day.