Thursday, February 21, 2013

Goodrich Earnings Call

This morning, the Goodrich management team provided a very robust report on their plans in the Tuscaloosa Marine Shale play.  I commend them for providing an excellent, thorough, and accurate presentation.  I believe that they captured the role of "TMS Inspirational Leader" today.  They presented their perspective with great conviction and their supporting technical data will be posted on their website on Monday.  With the execution of their strategic plan, they have the opportunity for a "company maker" in this play. Stay tuned.
I've highlighted what I consider to be the key points below in "blue".

TMS Discussion (most of the call):

As we have stated before, we do not believe current natural gas prices justified drilling for dry natural gas reserves, and as such, all of our 2013 drilling plans are associated with our oil-rich Eagle Ford and Tuscaloosa Marine Shale plays. 
In addition, we believe the lessons we have learned in the Eagle Ford will be very valuable as we increase our activity in the Tuscaloosa Marine Shale play and work to reduce cycle times and total completed well costs in this new emerging oil play.
And finally, moving to the Tuscaloosa Marine Shale. Rob is going to give you a very solid update on the play, but before he does, just a few comments from me.
While the Denkmann well suffered a series of frustrating mechanical issues that prevented us from being able to produce the well and resulted in a meaningful charge to exploration in the fourth quarter of last year, we do plan to come back and develop this acreage at a later date.
We are extremely pleased with the performance of the Crosby 1H well, which continues to outperform our expectations. The combination of the Crosby early time performance and the increasing age of the older longer lateral wells has further increased our confidence in the preliminary range of EUR expectations, and Rob will share those with you in just a second.
In addition, our Crosby well is located in Wilkinson County and is approximately 25 miles west of the EnCana Anderson wells and the Mid County, Mississippi. Therefore, the Crosby well represents another significant data point, further delineating our large acreage position in the TMS.
Finally, while we still have work to do, our knowledge of and solutions for the drilling problems experienced by a number of early wells in this play is improving, and we are increasingly confident that we will continue to see improving drill time results and improved total well costs in the TMS in 2013.
With that, I'll turn it over to Rob for an update on the TMS.
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Thanks, Gil. Needless to say, we are extremely pleased with the results from the Crosby well and the TMS. As we mentioned in the release, the well peaked at an average 24-hour rate of approximately 1,300 barrels equivalent per day on a 15/64 inch choke with approximately 1,200 barrels of oil and 600 Mcf of gas per day. The well has averaged 1,200 BOE per day over 15 days from a similar choke size, and is currently producing at that same rate.
Based on the current production trend, we expect the wells to produce an excess of 30,000 to 33,000 barrels of oil in the first full 30-day period. This well is capable of producing at a much higher rate on a more open choke size, but as we have seen in our other shale plays, we feel prudent to maintain a conservative early flowback plan, which will maintain maximum reservoir integrity.
We are very confident of the resource potential of the play. We're plotting production data from public sources. The Anderson 18 well has reached cumulative production of approximately 100,000 barrels of oil equivalent in approximately 7 months of production, which is significantly better than industry performance in the oil window of the Eagle Ford and compares very favorably to upper tier Bakken wells which reaches similar amount production in about 12 months.
Factoring in current LLS pricing of approximately $115 a barrel and 20% royalty, we generate gross and net revenue of $11.5 million and $9.2 million, respectively in approximately 7 months.
The Anderson 17, which has a shorter lateral length by approximately 1400 feet than the Anderson 18, has reached cumulative production in excess of 80,000 barrels of oil equivalent in 7 months, which is similar to many of the best Bakken wells at roughly the same point in time.
TMS production is approximately 90% to 95% black oil, priced off of LLS, which has a current uplift of approximately $20 over WTI. So as I described earlier, these BOE production numbers are significant not only from a well performance basis but in cash flow generation.
We now have a approximately 8 to 13 months of production from the recently drilled and properly stimulated TMS wells, which production profiles have all gone hyperbolic with the rates of decline flattening considerably.
As a reminder, in all shale plays, you typically see wells go hyperbolic beginning around months 6 to 9, and the TMS is no different. The wells to date have also been flowing a 5.5-inch casing over the first few months, and we feel by running tubing earlier in the life of the well, we can improve early production rates and rates of return going forward.
When evaluating public data, we have generated preliminary tight curves ranging from 400,000 BOE per well on short laterals to as much as 800,000 BOE per well on longer laterals such as the Anderson 18 and likely the Crosby,which to-date has tracked above the Anderson 18 even though the lateral length is approximately 2,000 feet shorter and the well had 5 fewer frac stages.
Through 8 months of production, The Anderson 17 is tracking our mid-case tight curves of approximately 600,000 BOE. We would obviously like to see more wells and more history from these wells to feel comfortable with these tight curves at this point in time and believe they establish a solid range of potential EURs.
In addition to commercial rates of production and higher oil pricing, the play has certain additional inherent advantages such as: Number one, our gas has hit very high BTU content with 8 gallons of NGLs per million cubic feet of gas, which calculates to approximately 190 barrels of liquids yield per million cubic feet of gas produced. Number two, we have a 5% lower royalty burden display than what we have in the Eagle Ford with average royalty across our acreage of approximately 20%. Third, we have a 2-year severance tax abatement on our Louisiana wells and expect something similar in Mississippi. And fourth, we have very little infrastructure and surface constraints, and that the oil is trucked from the lease for approximately $2 per barrel differential off of LLS pricing, and our acreage is located in the rural area of supported landowners.
Most of the wells drilled to date have either had drilling issues caused by well-boring stability from a specific 10-foot interval which we call the rubble zone or has been drilled and evaluated with a considerable amount of science performed on the well like the Crosby, where we drilled a pilot hole, logged, cored and evaluated the formation.
Our coring of the Crosby indicates the quartz content and the lower half of the TMS comprises approximately 50% of the formation and the clay content is lower, both of which are positive indicators of a higher-quality source rock.
Going forward, we think we will take our current well cost estimate without science or drilling issues of 12.5 million to 13 million to 10 million to 11 million over time for reproduction and drilling days, better service company pricing due to increase capacity in the field, net drilling, zipper fracs and other efficiency gains.
When factoring in our mid-case type curve of 600,000 barrels equivalent, which is, again, driven off of production data from the Anderson 17H well, and using a $13 million completed well costs and $90 WTI pricing, we are projecting close to a 40% rate of return, which is very competitive with other nonconventional oil place.
As we drive costs down, we expect to see an incremental 10% to 15% improvement in IRR for every $1 million of cost savings. And if we can hit our target of a $10 million completed well cost, we would generate in the neighborhood of a 75% internal rate of return.
In all of our horizontal plays, our drilling team has demonstrated the ability to reduce costs over time as they nail down these specific best practices for each area. This is confirmed by looking back at each of our primary plays and tracking drilling days to total depth.
For horizontal Cotton Valley wells, we started at 48 days spud to TD when we first got started, and ultimately wound up at 36 days when we finished. Our Haynesville drilling went from 46 days to 33 days stud to TD, and our Eagle Ford from 23 days to 10 days stud TD. When we reduce the drilling days in the TMS and it will happen, we expect a cost savings of $90,000 to $100,000 per day. So for every 10 days of reduced drilling time, we expect to generate an approximate $1 million of savings.
Pad drilling service company capacity additions, zipper fracs, et cetera, should provide the additional savings over time to allow us to reach our target well costs.
Another activity in the field, we have a 12% interest in the Ash 31-1 and 31-2 wells, both of which landed above our rubble zone and are currently being frac-ed, as well as the Anderson 17-2 and Anderson 17-3 wells, with the Anderson 17-2 well currently drilling to be followed by that 17-3 well.
Given our increasing confidence in the play, we are accelerating the timing of our next operated well and expect the spud to Smith 29-1 well in April.
We will roll out TMS slides in our management presentation next week as the conference season kicks off in earnest, which will exhibit the data I just gave you and I think show you why we are encouraged about the play and develop the potential of our 135,000-acre block.
Focusing on the results for the quarter. Production was 6.6 BCF equivalent with average production of 3,600 barrels of oil and 50.3 million cubic feet of gas per day. Our volumes were negatively impacted by the mechanical issue on the Denkmann well, which is scheduled the future development location.
In closing, the Eagle Ford and TMS will continue to drive our low volume growth for 2013 and beyond. The improved efficiencies and reducing drill times and well costs in all of our plays have us confident that the same will occur in the TMS, which will unlock significant value for the company.
With that, I would like to turn it over to Jan Schott to walk you through the financials.
Jan L. Schott - Chief Financial Officer and Senior Vice President
Exploration costs for the quarter includes the nonrecurring expense of $12.8 million or $1.95 per Mcfe for Denkmann well mechanical issues that Gil discussed earlier.
We are projecting a 0 tax rate for the full year of 2013. We are also confirming the previous CapEx guidance range of $175 million to $200 million for 2013. Following the success of the Crosby TMS wells, we expect Eagle Ford Shale at the low end and TMS at the high end of 2013 CapEx ranges previously given.

Question-and-Answer Session
Operator
[Operator Instructions] And your first question comes from the line of Mike Kelly with Global Hunter Securities.
Michael Kelly - Global Hunter Securities, LLC, Research Division
Rob, with your extremely compelling TMS comments, and I just kind of wanted to -- if we took down the list of things that you've already accomplished and the industry's already accomplished in the play, this proven that clay was going to be an issue, that was the first big scare. You've figured out the proper completion technique to get a really strong first month rate. You now seem to have the history that supports cumulative production stacking up even better than what's it seem to be the best oil plays in the country. You've got line of site to get drilling costs down to $10 million a well. What is left to prove in your eyes to get you to come forward to the market, do a JV and really garner a strong price that we've seen in some other basins?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Yes, Mike, thanks to that question. I think more wells spread out and little more history would be helpful, but we're pretty comfortable especially when the analog is the Eagle Ford in our tight curve analysis to date, we would expect perhaps some variability across the play, whether it's North or South or East or West, but the good news is that, as Gil said, these wells are 25, 26 miles apart between Anderson and the Crosby wells, and we have a huge percentage of our acreage obviously is in Mississippi and in those areas. So I think more wells and more history from those wells will clearly be helpful as to determining whether there's any variability across the play. But as we've said before, our plan is to drill the initial well, delineate the acreage and bring in a -- either a financial partner or an industry partner at the right time, at the right price and this certainly strengthens our hand.
Michael Kelly - Global Hunter Securities, LLC, Research Division
Got it. And if we could just talk about the timing of the next incremental data points, you had mentioned your well, the Smith well and the EnCana well, that you have working interest in, should we expect to have press releases out on those EnCana wells, just to kind of monitor the progress here?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Yes. Mike, this is Gil. As Rob said, we are currently frac-ing the 2 Ash wells. Those wells will be frac-ed back-to-back. We do have an interest of about 12% in both of those wells, so as soon as that data is available, we would put that out. I don't know exactly that will be in terms of the ultimate timing, but let's call it the latter part of March, second half of March feels about right. Anderson wells are currently being drilled. We don't -- do not know the specific time yet of the frac schedule or when those well will ultimately be done, but I would move that back probably another month, 1.5 months, so late April to the first part of May would be the best guess we could give on that at this point in time.
Operator
Your next question comes from the line of Ryan Todd.
Ryan Todd - Deutsche Bank AG, Research Division
First question on costs. I mean, how should we think -- there's been a lot of science involved both on your part and on EnCana's part, so far on the drilling. As we think over the course of the rest of the year, how should we think about the transition from science-driven wells to more development-type wells, from a timing point of view? And for example, the Smith well, is there anything different that you're doing on the Smith well and then the Crosby well as well?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Sure. Well, I think -- this is Gil, by the way. We think that a lot of science has been done. There may be a few other places that we might decide to drill some pilot holes and take some additional core data. But to a large degree, I think we just kind of accomplished that. So I think you can generally think about us drilling wells without pilot holes. If we do the best we can on the Crosby, of trying to normalize that back to what we have done there, had we not had the science and the pilot hole, we felt it was about a 45-day cycle time, is a pretty good estimate to what it would have been, to spud the TD. That would kind of get us back in the upper range of where we think current costs should be, which -- call it $12.5 million to $13 million. So I would say the next kind of letdown, as Rob kind of talked about in detail, was the anticipated improvement on cycle times, improving the drilling and the bit selection, downhole assemblies, working around the rubblized zone. We see those as kind of the next leg. And if we could certainly drive that from, say, 45 days down to 35 days in the next 6 to 12 months, then you're starting to, as Rob said, shave $1 million off of that and perhaps, get down to something under $12 million. One of the things we're most encouraged about, however, is based on the performance and the preliminary type curves, even at $13 million and something even remotely close to where current LLS pricing is, we think we're generating very substantial rates of return.
Michael Kelly - Global Hunter Securities, LLC, Research Division
And then if I could ask a follow-up on the type curve. Would you be willing to say, I mean, I -- what you think the decline rate, maybe like the first 12-month decline, is on the type curve?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Well, as Rob said, we plan to rollout our type curves. We'll have a 3-curve presentation which will come out on Monday, in our management presentation, so you'll be able to look at that and see exactly what the decline rates are.
Operator
Your next question comes from the line of Brian Corales with Howard Weil.
Brian M. Corales - Howard Weil Incorporated, Research Division
Just kind of digging down, maybe in a little bit more details, on your second operated well, what are you all estimating on drilling time?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Yes. So the Smith well, Brian, is roughly about 40, 45 days drill time, and be in front or inside, it's probably in the higher-end of that, that 45 days, by the TD. Probably, we'd come inside of that.
Brian M. Corales - Howard Weil Incorporated, Research Division
Right. Okay, okay. And can you -- I know you did some -- a little bit of testing, but is that about what the Crosby was and maybe on a normalized basis?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
I can say -- this is Rob. I can tell you a well that is interesting -- one of the Ash wells that's currently being frac-ed by EnCana, which is -- it didn't have the science in it. We have gone ahead and frac-ed that well, similar to what we did on the Crosby well. We think we could be in the $12 million to $12.5 million range, certainly, not north of $13 million. Then I got to pop a bigger frac job, has been published on the, I guess, the Tuscaloosa blog. But I think as -- assuming that well stimulates similarly to what we've seen when landing below the rubble zone, then we're likely to land above the rubble zone on the Smith well, and if that's the case, that's probably a good potential marker in the $12 million to $13 million range.
Brian M. Corales - Howard Weil Incorporated, Research Division
Okay. And I mean, I think what I'm about to ask has been asked by everybody in different ways, but I mean, it seems like -- I know it's extremely early and the results thus far have been, I guess, much better than the market and most have thought. What is your worry now? I mean, is there a worry that at least a good portion of your acreage doesn't work? Is there a portion that it's not economic? Is it truly a cost issue? Do you all really have a worry?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Well, Brian, it's Gil. We always have worries. We're paid to worry. So yes, we have worries. But we're -- as we've been saying and trying to say, as clearly and concisely as we can, that we're very encouraged by what we've seen. As we look geologically, and as we've said, at the very beginning before we bought our first acre, we did an exhaustive study of some 300 wellbores that had drilled through the TMS, chasing the lower conventional play. And we see a broad consistency of at least thicknesses and log responses. What we don't know, I guess, is specific point-to-point. What is exactly the mineralogical makeup, and are we going to see a 50% quartz-type composition, which we think is a very positive indication of source rock, across the entire play. We can't fully answer that. We have seen it in several places now, so we're encouraged. Secondly, we have a very quiet, stable deposition environment here, which lends to very broad deposition without dramatic changes in rock properties. So that's an encouraging point. If you just ask me, I'd say the number one concern is moving from where we are today to shaving off another couple of million dollars of drilling costs. We're confident we'll do that over time, exactly when and how it occurs, is a bit of a question. But clearly, that's a big focus for us. We're delighted with what we've seen in the well performance, and the only thing we got to do now is just get the costs down a little bit.
Operator
Your next question comes from the line of Leo Mariani with RBC.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
Obviously, a lot of TMS questions have been asked here. I think on EnCana's recent conference call, they talked about $15 million well costs, and you guys kind of referenced $12 million to $13 million. Any idea on what the potential disconnect may be there?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Yes. We can't comment, obviously, on what they said other than we read it like everyone else. And I believe, if you read the wording, what they said was they were budgeting $15 million. And we typically try to build some cushion into our budgets as well, so that our -- so that we can come in on our CapEx budget. We can say, on the other hand, which we're -- much of which is public data in Mississippi, we're seeing proposals and AFEs that are in the $12.5 million to $13 million range. So we don't know why they would be saying $15 million other than that's what they included in their budget. They may be planning, as Rob mentioned, to pump some higher profit jobs into an idea of bringing up performance even higher than what we've seen so far. But we had to direction back to them for further answers.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
Okay. So when you reference the AFEs for $12.5 million to $13 million, that's well that you're participating with them in this well, right?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
That's correct. And that would be targeting about a 7,000- to 7,500-foot lateral and roughly, 25 frac stages, pumping something on the order of about 450,000 pounds of proppant per stage. You want to go longer than that, add more stages or pump more proppant, obviously, the costs will go up.
Operator
Your next question comes from the line of Ronald Mills with Johnson Rice.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
A follow-up on what you just said, Gil, the 450,000 pounds per stage, it sounds like EnCana is talking about using a lot more profit in the Ash wells. What's your thought process regarding the 450,000 pounds versus the 750,000 to 1 million pounds per stage? And if you look at it, what do you think the difference would be in -- on a per stage completion between those 2 methods?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Yes. So Ron, this is Gil. I will say that we obviously, looking to [indiscernible], are pretty delighted with 450,000 pounds of proppant. That being said, what we have witnessed today, through all the wells in the play, would be that as proppant amounts per stage have gone up, I'm trying to otherwise compare in apple-to-apple in terms of lateral links and numbers of stages, you have seen improved performance from the wells. So thus far, there's somewhat of a linear correlation there, and we think it makes perfectly good sense to go ahead and test the upper limits of that correlation to see, can we add a little bit more cost for significantly better wells. And we think that's a worthy exercise and are fully supportive of that. In terms of the incremental costs, it's going to depend on exactly where you land in terms of additional proppant. If you went from 450,000 to, say, 750,000, you're probably adding $35,000 to $45,000 per stage of additional costs. If you went up to 1 million pounds of proppant or even over that, it's probably going to take you to $60,000 of additional cost per stage. So I think we're -- we would look at a bigger job, significantly bigger than a 450,000-pound proppant per stage job as science, at this point, and let's just see how the results come in.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
And what -- if you look at your $13 million -- or $12.5 million to $13 million, I guess I'm kind of back into this, how much is drilling versus completion? And how does that break down on your per stage completion costs?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Yes. Ron, I think -- and, of course, there's more completion cost over and above just the stimulation portion, but we're kind of running 40% drilling, 60% completion, currently. And then obviously, that would be skewed to the upside, if you're pumping bigger frac jobs. But call it, 135,000, 140,000 per stage, depending on how much fluid and profit you'd pump. Yes, and then as Gil said, incrementally, over and above that depending on how large you pump. So for us, the one thing we can control the most, I think going in, is just best drilling practices and shaving days. And as I said in my prepared remarks, we've done that in every one of our plays, and no question, I feel like we'll do that here as well. But we're having to contract with service providers who are having to drive in from other areas, and that's certainly increasing the cost of services. And once the play has proven up, that incremental capacity will help drive down cost there as well. So I think we've got a couple of -- or 2 or 3 areas that are going to drive the cost down. Pad drilling, just like we've seen in the Eagle Ford, will also take it down another lag between just getting rigs and combining surface facilities to zipper fracs, all the efficiencies you gain from doing that will help us drive that incremental cost down.
Operator
The next question comes from the line of Dan McSpirit with BMO Capital Markets.
Dan McSpirit - BMO Capital Markets U.S.
Rob, I was hoping you can review for us points made earlier in the prepared remarks, on the flattening of the production curve based on your observation of production history from other wells. I asked because it's really not a small point. And are you observing that the wells really are turning hyperbolic, maybe sooner than later, and if you could express a B factor?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Yes, I'll tell you what we -- in the slides, there's going to be a lot of proof in looking at those slides, as to the turn being made in the hyperbolic shape. We see it in every one of our plays. It's ironic that there's been, maybe some commentary out there, that the declines had been exponential in the early life of a well. Well, guess what, it's like that in every shale play because you're draining fractures, and then the matrix kicks in and it hurts the production. So any way -- anywhere we look at it on, for example, on Anderson 17, if you start plotting that, 0 at around month 6. You start to see the curves flatten pretty dramatically. And we've seen that all the way through all of those wells, including the Weyerhaeuser well, which is 13 months old now. We knew that going in. We were comfortable with that going in because there's a vertical well that's produced for 30-something years that has the 2.0 B factor. There's 3 short laterals that Encore acquisitions has drilled, that have been on since 2007 and 2008, that have any where from 1.4 to 1.6 B factors. Very well, it could be a 2-part curve here. We're kind of modeling initially a 1.3 B factor. With more wells and more history, we'll be able to refine that. But so far, we have a very nice tight fit. As Gil said, in response to Ryan's question earlier, we'll be able to provide that to you in our slide deck, which will be posted on our website beginning, likely, Monday morning.
Dan McSpirit - BMO Capital Markets U.S.
Got it. Very helpful. And as a follow-up here, is the risk profile different with the Ash wells, given that the laterals are being landed above the rubble zone?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Yes, Dan. This is Gil. I would say that we have, all along, felt like the ideal landing spot would be down in the bottom 20 to 25 feet of the TMS. We talked today about the quartz content in the lower half of the TMS. So landing above the rubble, as I would put you still within that range, it should be in the upper part of that range. So I say, we're anxious to see the Ash wells completed. We hope, or are confident that that's going to not be an issue. But we certainly would rather see that before we start making any definitive wholesale changes in our landing target across the play. It is about 50 to 55 feet off the bottom, so it's not dramatically different from the lower landing target at 25 feet off the bottom, and certainly, will still be in the lower half of the overall TMS. So as we look at life of seismic work that's been done, we're seeing stimulation indications far broader than that kind of a footage difference. So I think we're highly confident, but until it's done, we actually have some flowback results. I think we'll just wait and see.
Operator
;
Your next question comes from the line of Brian Lively with Tudor, Pickering, Holt.
Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division
Just more questions on the TMS. As we've -- from the outside looking in, there have been -- I would say, there is some conflicting data coming from various operators in the TMS. Rob, I really appreciate all the comments, very compelling from that standpoint. If you guys were to boil it down, though, what do you think the fundamental differences are between the various perspectives here? I know you want to comment on the competency of other companies, but what are you -- how are you guys seeing the picture different? Is it cost-related? Is it this matrix contribution issue? Is it variability? Or just what is it?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Yes. Brian, one of the -- another slide or certainly commentary we're going to start discussing on Monday is lateral links, frac intervals, frac stage links and amount of profit pumped, and we see a direct correlation, as Gil said, with profit pumped per stage to results. So far, it's been, I would say, somewhat linear. But no question, if you drill a short lateral with small amount of profit pumps, the well is not going to do very well. And we think that's certainly has been performed in several wells. Several of the earlier wells were under-stimulated. And we think it's important that you give it the best shot by pumping, certainly, higher amounts of profit. Where you land the lateral, as Gil said, and I think I said in my previous -- in my prepared remarks, we're seeing a high quartz content, almost sand and siltstone-like in the lower half of the TMS. If you land above that, very well, it could be problematic in getting your frac off and stimulating appropriately. We're certainly seeing very good results by landing in the lower 25% or so of that formation. Those are the 2 things that jump out to us. Now whether this geographic or geologic differences, as you head South, that's a point that we'll have to just study and try to determine, as you get deeper, as you get more thermally mature and less productive. We just don't know the answer to that yet, but certainly, hope to figure that out as well.
Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division
And as a follow-up to that, the GOR seemed pretty low upfront. Are you guys seeing an increasing GOR over time? It's good to have oil, but it's as good to have a drive mechanism.
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Yes, Brian, this is Gil. We're seeing very little change in GOR over time, in any of the walls that have produced thus far. A little bit interesting [indiscernible] because slightly higher GOR than we've seen in the other wells. It doesn't necessarily make a whole lot of sense to us, and then we're essentially on strike with the Anderson wells. So no other region that we'd have a slightly higher GOR. I would just say that, as Rob said, we're not pounding the table on any one particular type curve, which you'll see from us on Monday of next week. It's 3 different type-curves ranging from a low of 400,000 to a high of 800,000. And we're doing that based on the data that we've seen and we've finally, now, at over a year with the first grassroots lateral, being sufficiently online production, getting to a comfort level. We think it made sense to put it out and start to talk about it. What others are saying, we're -- they're actually entitled to their opinion, and we're very comfortable with saying what we say, when we say it, how we say it, because that's what we believe, and we'll see how the play turns out a year from now.
Operator
Your next question comes from the line of Mike Scialla with Stifel.
Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division
If I heard you right, I think you had said that for the Smith well, you were planning on landing the lateral above the rubble zone. Is that, in fact, the case? And -- or do you plan on waiting to see results from the Ash wells before you make a decision on how you're going to drill that well?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Yes. Mike, this is Gil. I would say, probably both. We currently would plan to land above the rubble zone, but in the case that we see something negative from either of the Ash wells, we might reconsider that. But right now, we would be planning to land just above that rubblized zone.
Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division
Okay. So without the liner, and a little bit different completion than what you did on the Crosby?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Well, the liner part would be correct. Yes, we would not plan to run a liner. And frankly, even if we were to move and go back to the lower target, we would be drilling a slightly bigger hole with a liner contingent plan, but not definitively planning to run a liner unless we felt we had to during the course of drilling the well.
Operator
Your next question comes from the line of Richard Tullis with Capital One.
Richard M. Tullis - Capital One Southcoast, Inc., Research Division
A couple of questions I don't think have been touched on yet. Should you get to a jade point of monetizing the TMS with -- through a JV. Would you be looking more for -- what would be your preference there? Would it be more drilling carry or a large portion cash to pay down debt immediately or similar outright sale of some acreage? What would be your preference at this point?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Yes. Richard, this is Gil. I would say this, our strategy, as we tried that line in our comments is, we're going to maintain adequate and ample liquidity into our revolver, and we're going to take steps to address the convertible notes during the course of this year. So I think that leaves us with pretty good flexibility to let the opportunities come to us in the TMS, and we're not going to try to force anything or push anything that doesn't make sense for our shareholders. We'll continue on with our development, and so -- we're a bit indifferent to exactly how it might come. We're not so indifferent as to what the size might be of the acreage. And unless we feel like we're getting sufficient value that can allow us to accelerate, and therefore, create incremental value, we won't be takers of anything. Cash and carry probably feels the best, call it 50-50, but if someone came to us with the right valuation, we would certainly consider a higher carry percentage. And we are all in to develop this asset, and really indifferent as to exactly how that occurs.
Richard M. Tullis - Capital One Southcoast, Inc., Research Division
Okay. I know there's a couple of packages on the block right now in the TMS. What are you hearing on current environment for M&A activity there?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Yes, well, clearly, there is some acreage on the environment. Exactly how that acreage stacks up with ours is a bit of a question, and we'll just have to see how that process goes through the marketing process. And as I said, we're not going to try to jam ourselves into the middle of something. We're happy to continue to be patient and develop our block.
Operator
Your next question comes from the line of Curt Freeman [ph] with Simmons.
Unknown Analyst
Turning the focus a little bit to the Pearsall. It sounds like that well, that was initially supposed to be spudded in Q1. It's going to be delayed and possibly not to spud this year. Is that correct? And any color you can provide there would be helpful.

Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Yes, this is Rob. Well, I think the Crosby resolve, obviously, has us pretty excited and accelerating the spud date on the Smith well. And when we budget quarterly, we're obviously looking to spend as little money as possible in the early first half of this year, while we prove up the TMS. And that's really the driving force behind that shift. Now as we said in our prepared remarks, it's still on the schedule for later this year. We're monitoring production a little more time, when watching the production doesn't hurt us on the Pearsall. And that is just a very new play. So it's kind of a combination of lack of wanting to spend the extra capital in the Pearsall at a time where we're accelerating the spud date on the Smith well.
Joseph Patrick Magner - Macquarie Research
Okay, understood. Clarify, there was a comment about returning to the area where the Denkmann well has drilled. Has that well been abandoned? Or do you still plan to continue remediation efforts, or reenter that well and drill sidetrack?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Yes, the well has not been abandoned, and we are evaluating the best way to go about redeveloping that acreage using that wellbore. If that what's makes the most sense. We have not finalized our study at this point.
Operator
At this time, I have no further questions. I would now like to turn the call over to Mr. Goodrich for closing remarks.
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Thank you, Kim. And thanks, everyone, for your participation this morning. As you can see, we're very encouraged by the results of the Crosby and the overall TMS play, and we look forward to additional development in data points and we'll share those with you as they come in. Thank you.

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