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Good morning, ladies and gentlemen, and welcome to the Third Quarter 2019 Black Stone Minerals L.P. Earnings Call. [Operator Instructions]. I would now like to turn the conference over to your host, Mr. Brent Collins, Vice President of Investor Relations. Please go ahead, sir.
Thank you, Bella. Good morning, everyone, and thank you for joining us either by phone or online for Black Stone Minerals' Third Quarter 2019 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 forward-looking -- to the cautionary information about forward-looking statements in our press release from yesterday and the Risk Factors 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 yesterday, which can be found on our website at blackstoneminerals.com.
Company officials on the call this morning are Tom Carter, Chairman and CEO; Jeff Wood, 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. With that, I'll turn the call over to Tom.
Thank you. Good morning to everyone, and thanks for calling in to the third quarter conference call. We feel that Blackstone reported solid results for the third quarter. Total production for the quarter averaged 49,000 BOE per day. Royalty volumes increased 14% year-over-year, driven mostly by growth in our Permian and Shelby Trough production. Our working interest volumes declined by 25% versus last year, and that was done on purpose.
We participated as a working interest partner with two key operators during the last downturn in order to facilitate continued development of our mineral acreage. That program kickstarted the current original round of Shelby Trough development and create a lot of value for our shareholders. We continue to benefit from that working interest investment even after farming out all of our capital obligations through additional override volumes and back-end potential.
Overall, our production is trending in line with our revised expectations. You'll recall that we increased our full year production guidance last quarter, and we're tracking to be right in the middle of that range for the year. Weaker commodity prices impacted our financial results for the quarter, including wider differentials for natural gas and lower NGL realizations. Distributable cash flow was down a bit for the quarter, but we were able to maintain our distribution at $0.37 per common unit while generating excess distribution coverage, which allowed us to pay down $23 million of debt in the quarter.
At the end of the third quarter, we had a total of 97 drilling rigs operating on our acreage. Over 60% of those are running in the Midland and Delaware basins. Both the Haynesville and the Bakken had 10% or more share of our rig count with the balance spread across the entire portfolio.
We continue to see good levels of permitting activity and well additions despite the general slowdown in drilling activity. During the quarter, we added 4.8 net wells on our acreage. Consistent with what we've seen over the last year, the largest contributors were the Midland and Delaware basins with 1.7 net wells. The Haynesville, Bakken and Eagle Ford contributed a further 2.1 net wells, with the remaining net wells coming from outside the top 4 plays. In 2018, we added 21 net wells across our acreage, which was a company record. Year-to-date, we've added a little over 16 net wells. So I think we have a great chance to meet or beat that record in 2019. In fact, we're aware of approximately 10 net wells in the Permian alone that have recently been completed or are in the process of being completed, so those wells could potentially move that number up meaningfully if we see them come in this year.
In terms of permitting activity, we saw 454 horizontal permits added on our acreage during the third quarter, which is down slightly from 474 last quarter. The decrease related to fewer Eagle Ford permits. Permitting activity was flat in both the Midland Delaware area and the Haynesville, and we actually saw an increase in permitting in the Bakken.
We didn't have any meaningful acquisitions during this quarter. The macro environment is, frankly, tough right now. And in response to that, we've pulled in our horns, some on acquisition -- on the acquisition front and are being more selective. We haven't seen anything that we can't live without. We're being a bit more defensive at the moment. And while we're in that mode, we'll prioritize paying down the revolver, which will position us for future acquisitions or share repurchases.
Last quarter, we discussed the slowdown in activity in the Shelby Trough, particularly on the part of BPX, formerly BP, lower 48. Following our earnings call, we received a number of inbound calls from various parties inquiring about that project. The level of genuine interest is encouraging, and we're in discussions now with a few of those groups. Our focus has been on getting activity moving out there again as quickly as possible, and I think things are proceeding well on that front. Obviously, the Shelby Trough is an important asset to us and has long-term implications on cash flow profile of the company.
In addition to our efforts in the Shelby Trough, we are doing everything we can to promote additional activity on our acreage generally. Those of you who follow us regularly know that active management of our acreage is something that we believe differentiates us from others in our space and is particularly beneficial in times such as these, with commodity prices where they are and access to capital so restricted for E&Ps. We are coming to the end of 2019 with strong current distribution coverage and a very attractive distribution yield, over 11% at the current price -- unit price. We plan to give our initial guidance around 2020 as usual, in connection with our fourth quarter call in January -- excuse me, February.
With that, I'll turn the call over to Jeff.
Okay. Thank you, Tom, and good morning, everyone. So we released our third quarter 2019 earnings release yesterday afternoon. As Tom mentioned, our reported total production of 49,000 BOE per day was at the midpoint of the revised guidance range that we issued last quarter. And of course, that range was revised upwards from our original guidance that we issued in February of 2019.
Royalty production was near the upper end of that guidance range, and costs were generally favorable compared to guidance. Specifically, both G&A and DD&A are trending below our expectations. Production costs and ad valorem taxes came in a little bit higher on a percentage basis from what we guided. That's as a result of lower oil and gas prices bringing down revenues. All that information is available through the earnings release. So here, I'm going to focus on a few of the items that impacted our financial results for the quarter.
The first of those items I want to touch on is pricing. We're all aware that WTI and Henry Hub prices have moved down through most of 2019, although we have seen a nice bounce here recently. We're impacted by that, but frankly, our hedge portfolio is designed to mitigate that impact. And it has, as you can see, by the positive cash realizations from hedges that we recorded this year, including almost $14 million in the third quarter. Because we don't market our own volumes and, therefore, don't have perfect visibility on where the oil and gas is ultimately sold, we have not historically hedged price differentials between those sales points and hub prices. Those differentials for oil actually improved this quarter, but gas differentials worsened.
In addition, NGL prices were just historically bad in the third quarter, trading down to levels that we haven't seen since early '16. So the combination of worsening differentials and lower NGL prices caused our realized natural gas prices for the quarter to fall below the Henry Hub price, which is an unusual occurrence for us. Overall, our realized gas price for the quarter was $2.09 in Mcf. That's down 20% from last quarter and down over 35% from the third quarter of last year.
The other topic I want to cover is the balance sheet and our current liquidity because as Tom said, we've been even more focused on that in the current environment. We reduced total debt by $23 million in the third quarter to $413 million as of September 30, and our debt to trailing 12-month EBITDAX ratio came down a little where we are now under 1.1x. We had a small price related -- price deck-related decrease to our borrowing base in conjunction with the fall redetermination that just occurred.
Despite that, we had almost $240 million of liquidity available to us at quarter end. As of last Friday, our revolver balance was down to $380 million, so we continue to make good progress on that front. These lower debt levels and greater liquidity levels are especially important in this difficult energy environment. Not only does it further derisk what is [indiscernible] minerals business model, but the extra liquidity also positions us to acquire assets at a time when frankly, we're not too excited about using our equity as a funding source for acquisitions. So overall, we remain in a very strong financial position, which we hope will set us up to succeed even if this tough energy environment continues.
Finally, and this does not have a direct impact on the financials, but some of you may have seen that we filed an S-3 registration statement last Friday. That statement covers the 14.7 million common units underlying the $300 million of preferred shares that we issued to Carlyle 2 years ago. Carlyle now has the right to convert its preferred shares to common, so we needed to register those underlying common shares. It certainly does not indicate that we plan to sell additional shares, and we have no indication from Carlyle that they intend to convert out of their preferred position into common at this time.
With that, Bella, I will turn the call over to questions.
[Operator Instructions]. Our first question comes from the line of Pearce Hammond with Simmons Energy.
So my first question pertains to capital allocation, just sort of your thoughts on unit buybacks versus distributions versus debt reductions. Obviously, this quarter, you paid down some debt, $20 million worth. But given where the units are right now, does that kind of bump up the priority on unit buybacks? So I just wanted to get your thoughts on that subject.
Sure, Peter. This is Jeff. That's a great question. It really just depends on the opportunities at the time. I mean the first priority always for us is to maintain a really strong balance sheet. So we were -- as you cited, we were focused more on that this quarter with using virtually all of our excess cash flow to reduce debt balances, and we just think that positions us to be in a better position to take advantage of opportunities down the line, especially when, as I mentioned in my comments, we're not too excited about using equity directly to finance acquisitions.
I think from that point -- and we feel pretty good about our liquidity position today. Based from that point, it's just what gives us the best opportunity. I think as you mentioned, the potential for share repurchases is certainly there. We are seeing some interesting things in the acquisition environment. So it's just what provides us the best kind of long-term IRR, ROI on the use of that capital. So again, kind of focused on debt reduction, but we feel pretty good about our liquidity today. And it's just going to really depend on primarily what we see out there in the acquisition market going forward.
Great. And then my follow-up, Jeff, it pertains to the Shelby Trough. And I know you guys are working hard to get some other producers in there drilling in the area. But given that XTO is postponing the completion of some of those DUCs that I think you thought might get done last quarter when you reported, how does it impact the 2020 production profile for the company? Because I thought previously, we had thought it might be more of an impact on '21 rather than on '20.
Yes. So Pearce, maybe I'll take that and then see if Tom may just want to comment on Shelby Trough progress more generally. I think that's right. So last quarter, the expectation was that XTO was going to move in and do those -- complete those DUCs on a little more rapid time frame, and that was going to push out the impact. I think now, look, Shelby Trough is one of our bigger areas of production. I will point out again that it's dry gas, so it's not as big a percentage of our total cash flows. But I think with those DUCs, our current understanding of what XTO's plans are out there, which is a little more delayed than we originally thought they were going to be.
I think as we get into the back half of 2020, we'll see more of the volume impact, just given the way that those wells generally come online, and stay at pretty flat rates for 12 to 18 months. So I think as we get into the back half of 2020, that will come more into play. As Tom mentioned in his remarks, we are certainly out there trying to pull every lever that we can to accelerate volumes, not only in the Shelby Trough but across our portfolio. So there's just -- there's a lot of balls in the air right now, and we'll have to see how some of those things play out. But yes, I think it's safe to say that with the delays on some of those completions, the effect moves forward a little bit, as you said. And Tom, I don't know if you wanted to?
Well, I would just make some additional comments on the Shelby Trough. We have in the Shelby Trough probably somewhere in the 550 to 600 viable locations out there. And at 30 wells a year, that's 20-plus years of inventory. And we're not anywhere near 30 wells a year. We are working to try to position the economics on those wells where they can compete for capital with other plays on a full cost basis, i.e., low, low entry but strong drilling commitments and working with our partners around royalty rates to allow them to have economic success in a constrained natural gas pricing market. But this is a very, very long-term project, and it's going to be around for a long time. And we are going to do everything we can to efficiently manage that property, to produce cash flow, to provide distributions to our unitholders for years to come.
[Operator Instructions]. Our next question comes from the line of TJ Schultz from RBC Capital Markets.
Just on the gas differentials. Is that something you expect to reverse? Do you hedge that going forward? I know you said you have kind of limited line of sight there. Or just any more insight on kind of what caused that impact this last quarter?
Well, I think -- TJ, this is Jeff, and others may want to chime in. I think you just saw a little bit of a perfect storm of a lot of Permian gas coming from the West and Marcellus gas coming from the East that all negatively impacted differentials around East Texas. There are a couple of large pipelines that are ones underway now that are -- that's meant to alleviate some of that, that will bring that gas down to the Gulf Coast. So I think you'll see it just kind of come and go until those pipelines are complete, just depending on how much gas is flowing into the area. So it's probably something that -- I have no idea if it would be as bad as it was this quarter. Again, that $2.09 realized price on gas for us was very low, but we'll have to see how that goes until those pipelines are completed.
As I said, it's really tough for us to hedge differentials since we're not the ones actually marketing the gas. Our producers do that for us. It's tough to have great visibility on exactly where the specific sales points are. So we have not historically hedged differences for that reason so that we don't get in a position that we're hedging something that we're not actually exposed to. So I don't think that practice will change, but -- yes, I don't know. Is there other comments? Yes. I think that's the position, TJ. I doubt we hedge it, and help should be coming in the near term on solving those differentials.
Okay. No, that makes sense. And then just on the distribution, thinking about coverage. Is there a certain level on kind of coverage where you kind of reevaluate the distribution level? Just how should we think about that over the next 12 months?
Yes. So this is Jeff. What I'd say is that we've found coverage to be very valuable for a number of reasons, right? One, it keeps the balance sheet in shape. It gives opportunities. Not only does it help to fund acquisitions or share repurchases or debt repayment in times when markets are more choppy, but frankly, it gives us a little greater flexibility in what we can acquire. For example, we have often acquired production that is more back-end weighted, right? So it allows us to sort of feather in a portfolio of acquisitions that doesn't just focus on PV-heavy stuff so we get cash flows immediately, but you know it's going to come off soon. And so it allows you to construct a nice acquisition cash flow profile that extends accretion across a number of years. And again, having coverage and not having to focus so much on the immediate impact of an acquisition has been very helpful.
So what I'd say is I think that, that's going to continue. And we will continue to look to have some level of distribution coverage as we go forward, and that will -- with us and with the board go into our thoughts as we're deciding on distribution levels.
Your next question comes from the line of Phil Stuart with Scotiabank.
I appreciate the information on the Shelby Trough. I understand that you are working on some kind of creative solutions to potentially bring in partners. Just kind of curious, I don't remember the last time that you all gave a well cost number for that area. But can you maybe remind us what BPX and XTO are averaging in terms of well cost in that area?
Yes. XTO -- sorry, this is Brock Morris. The XTO wells are in the $12 million to $13 million range, and the BP wells are about $18 million.
Okay, understood. And then I guess as you all are evaluating options, is there a potential that you all would participate in a working interest fashion in order to attract operators? Or is that kind of off the table since you all kind of pivoted away from that more recently?
This is Tom. I would tell you that everything is on the table in terms of looking out over the next 2 to 3 years in terms of proper management of our balance sheet as well as proper management of our distributions, our legacy long-term owners or owners of this company because of the distributions, we certainly like to maintain and grow our distributions. But sometimes, the industry doesn't allow that, and we're not going to chase growth just for growth's sake. We are very focused on distributions. We're also very focused on our balance sheet. And working interest can work for you at certain times. It's not our preferred way to go. But I would tell you that, that question that you asked is very much in our minds around how we are going to reconstruct the program over the next couple of years in the Shelby Trough. We'll have more on that later.
Your next question comes from the line of Pearce Hammond from Simmons Energy.
Just a quick follow-up. I'm just curious what you guys are seeing. I know you're not active right at this moment. But in the mineral market as far as acquisitions, is it a buyer's or seller's market? And specifically, what's kind of going on in the Permian?
This is Holbrook. It's more of -- the market's actually gotten somewhat slow. I think there is a broadening gap, in my opinion, between buyers and sellers. Sellers, especially in the Permian are still looking back to kind of '18 prices when things are feeling pretty good in the third quarter. And the market, just from the buy side, just got a little bit more rocky than that. And I don't think SAR's expectations have come in accordingly. That's just our opinion. So some of our peers out there have been more active on the acquisition front than we've been of late. But that's what we're seeing right now.
And with other public companies like one that IPO-ed earlier this year, does it make it a more competitive market? Or do you not necessarily all play in the same areas.
Yes. I mean, I think it's a competitive market right now. I mean as more information comes out on all these plays, people probably -- the pricing gets more and more efficient and everyone is working with a similar toolbox. So yes, I think it's -- the longer these plays go on, the more competitive it gets because everyone knows more about these plays.
But Pearce, this is Jeff. I mean, there was so much private equity money coming into the space in the few years before '19 that, I mean -- I don't know. I know that we felt like the competitive environment has changed a lot. It's been competitive now for a number of years. And just because someone went public, they may or may not get them more access to capital. I think a lot of these PE-backed guys were getting reupped, and there was a lot of availability. That company was active before they went public, and I'm sure they'll be active being public as well.
[Operator Instructions].
Okay. Well, we don't seem to have any further questions. So we thank you all for participating in our third quarter 2019 earnings call, and we look forward to speaking with you in the future.
This concludes today's conference call. Thank you for your participation. You may now disconnect.