With the sale of its West Edmund Hunton Lime Unit (WEHLU) closed in February 2018, Gastar Exploration (ticker: GST) is now positioned to become a pure-play Oklahoma STACK Play operator. In the STACK play, Gastar is targeting two producing formations: Osasge and Meramec.
Operational update
According to Stephen Roberts, Senior Vice President and Chief Operating Officer, “As compared to the first half of 2017, we have seen a reduction in the number of days to drill a well from 19.4 to 12.4 days and reduced completion days from seven to four. Based on efficiency improvements, our current cost per well is expected to be approximately $4.5 million for Osage wells and $4.7 million for Meramec wells.”
During 2017, Gastar spud a total of 11 gross (3.1 net) operated Meramec and 17 gross (11.5 net) operated Osage wells. In addition, Gastar completed 15 gross (3.8 net) operated Meramec and 16 gross (10.6 net) operated Osage wells and participated in numerous third-party wells across its 67,000 core STACK Play acreage. This highly contiguous position is 84% operated and 66% held by production.
So far in 2018 Gastar spud three gross (2.5 net) operated Osage wells and completed two gross (1.8 net) operated Osage wells.
Q&A from conference call
Q: Clearly, a much better shape post the WEHLU sale. But with that in mind, first, how are you guys thinking about the preferred dividend at this point? And then secondly, I noticed kind of a brief sentence in the press release that mentioned the potential for future property sales if necessary. I was just curious what those would be comprised of.
Senior Vice President and CFO, Michael A. Gerlich: Regarding the preferred, as we stated before, it’s always been and continues to be our intention to catch up and reinstate the preferred dividends. We say that we needed to complete the WEHLU property sale, and that’s now been completed. Typically, preferred dividends are declared by the 10th of a month with a record date about 10 days later, and then the dividends are paid at the month-end of the announcement. Again, it remains our intention to catch up the dividend payments in arrears, reinstate the preferred dividends. And those assumptions were factored into our 2018 budget and liquidity projections. So, it’s really not going to have the reinstatement will not have an impact on our plans for 2018.
Regarding the overall question on liquidity, obviously, the closing of WEHLU has given us ample liquidity, as I said, to execute our 2018 budget and should carry us into 2019. We continue to evaluate our capital needs and compare them to our capital resources and our ability to raise funds in the capital markets or through the sale of – really what the focus will be is non-core lease acreage. And our definition of non-core is more small blocks of acreage we own in sections we know we will not operate. We’ll either look at monetizing those or maybe trading them to enhance our working interest position in our operated sections.
So, fortunately, we have the ability to adjust our capital expenditures in response to changes in commodity prices, drilling results, liquidity and cash flows, as we operate the majority of our capital expenditures. So, we’re going to continue to review our options over the next few months, including strategic alternatives. But again, since we’ve got a pretty good handle on our outflow since we operate it, we’re not concerned about an immediate liquidity crunch.
Q: I was wondering, Stephen, you talked a lot about the operations there, and obviously, you get some better drilling and completion times in. As you talk about the Gen 3 completions, I think you guys are using some diverters and things. But is there anything else that’s kind of different in those that you’re seeing the good response from?
Senior Vice President and COO, Stephen P. Roberts: We mentioned in our previous call and even prior to that that we tried to reduce cost early last year by stripping out a lot of the additives and going to really a completion provider that we just weren’t happy with. And we’ve made all those changes, and we continue to test. And I mentioned that we’re continuing to test the various additive surfactants, clay stabilizers, diverters, et cetera, and certainly feel like we’re getting an uptick in our production performance associated with those.
Again, as mentioned too, I think it’s very important to note as well that we do see what we think is improved production performance here with the 35-stage wells. So, there is a likelihood that we will begin to transition most of our completions to 30 or 35 stages. Again, we’ve got more history on those than we do on a lot of the 25. So, we’re still watching those and still very pleased with initial results there. But again, we think that 35 stages are performing really above type curve at this point. So, that’s the direction we’re moving.
Q: And then also you talked a bit about, at some point, being able to shift from holding acreage to the pad drilling, and I think if I saw the number, you’re about two-thirds held by production now. As you see this year play out, where do you think that that number goes and when do you maybe start to look at the pad drilling for at least some of your operations in the future?
Stephen P. Roberts: I’ll take that and then may defer to Mike as well. But right now, our absolute focus is on continuing to push our costs down while simultaneously improving production performance, and that all in conjunction with HBP-ing the rest of our acreage. So, we will likely be fully HBP-ed sometime next year as we continue to add operated sections that may be pushed out a tiny bit based on a one rig schedule, but certainly watching other operators and noting the improvements they’re seeing from pad drilling and recognize that there are certainly significant cost reductions there that we can recognize from pad drilling. But again, our focus this year really is the HBP process and continuing to refine our execution and design.
Michael A. Gerlich: I’ll just add a couple of things following up on HBP-ing. He’s correct. We’ll have the majority of our operated HBP probably sometimes early 2019, at which time we will start looking at moving to pad drilling. We are aware of some of the operators in the STACK recently reporting some negative down spacing test results. We’re also aware that another operator that has acreage adjacent to ours has reported positive down spacing testing. Some of those tests were actually in close proximity to the operators that reported some of the negative results. At this point, we’re going to, as Stephen said, continue to focus on holding HBP-ing our acreage, and then once we start doing our own, we’ll talk about down spacing. But our spacing assumptions are basically on par to those with the good results. We’re looking at 6 in the Meramec and 7 wine rack in the Osage, and we don’t think we’ve been overly aggressive on that aspect. Obviously, it’ll be sometimes probably till 2019 until we can start proving up those assumptions.
Q: Operationally, what does the split kind of look like between Meramec and Osage as we go throughout 2018?
Stephen P. Roberts: Osage is definitely going to be lion’s share, and I think we said, 15 Osage wells and I believe 5 Meramec wells. So, definitely the lion’s share in Osage, and again we feel like the Osage exists and has significant thickness across our entire position, where we’re still testing that theory with the Meramec, certainly thick toward the southern end. And we continue to stretch that northern border. Some of our more recent, very successful Meramec tests have been 1 mile step out to the north of where we’ve previously been. So, we’re really excited about results of both, but feel like the Meramec to some degree is proven up, and we’re continuing to delineate and prove up Osage, so hence, the primary reason for the lion’s share being Osage going forward.
Q: You talked about running into the chert, and I think that’s in the Osage. Is that kind of running into stringers or just maybe talk a little bit more about that and how you’re dealing with that.
Stephen P. Roberts: Yeah. Oh, absolutely. It can be stringers and it can come and go. But we also see it in some instances where it can be a little more blocky and contiguous – but in either case, we think we have addressed it. We did run into it three or four times towards the end of last year and the beginning of this year, and it presented us with a few problems. If anybody out there is aware operationally, chert is virtually impossible to drill if you stay in that interval. And the BHAs that you have to use to drill in chert can be very conservative in terms of ROP.
So, we have developed a strategy basically of dropping our curve. Well, one – I guess it’s really kind of a three-part strategy. One, we’ve drilled enough wells now and delineated enough that we know, to a large degree, geographically and through vertical depth-wise where we’re going to encounter the chert. So, we’re anticipating it as we go. As we drill down through and looking for it, we’ll typically try to drill through that interval with our curve before we set 7-inch casing. And typically, you’ve got a BHA that’s somewhat worn at that point anyway. So, if you do a little damage to the bit, really no concern. Identify what you’ve got and get through it, set your 7-inch and now you’ve kind of set a target of where that chert is, and then quickly move back to a very aggressive BHA, i.e., a PDC bit and then continue with very smooth, very efficient ROPs.
So, that we have implemented actually on the last several wells and the last two have actually – we just TD-ed another one just actually yesterday and we’re at very good times. We’re in that 10, 11, 12-day TD time, so really excited about that and getting well times down. That was really our last lingering issue on drilling and virtually every other issue has been resolved at this point.
