Thursday, May 9, 2013

Goodrich Earnings Call Transcript

The transcript TMS highlights from the Goodrich earnings call.  I've corrected several typos.

Our ongoing transitions story from our company's production and reserve were dominated by natural gas towards a more balanced portfolio is very much on track and the emerging Tuscaloosa Marine Shale play adds a component with tremendous upside potential. However, financial and operational performance for the first quarter of this year was negatively impacted by a number of items including: offset well completion impact on production volumes in both the Eagle Ford Shale and Haynesville Shale, where we have recently initiated our plan of completing previously drilled gas wells; a number of unusual financial and operational expenses incurred and paid out during the quarter; and the roll-off of our 2012 natural gas hedges, impacting revenue and cash flow when compared with the prior period.


Moving to the Tuscaloosa Marine Shale. While currently representing only 25% of our full year CapEx budget of $200 million, the TMS is certainly a focal point for us as we continue to move towards larger-scale development mode. We continue to be very encouraged by the results we have seen thus far and believe we are gaining valuable knowledge as we move along this path. Our enhanced knowledge is both in terms of improved drilling procedures, which has led to recently improved drilling cycle times, and optimized completion techniques, including the types and amounts of fluids used, as well as the amount of profit per stage. We are confident these learning curves already have and will continue to lead to improved drilling times, reduced well costs and more repeatable well performance.

Finally, we have recently spud our next operated TMS well, the Smith 5-29-1, and plan to drill at least 3 additional operated wells in 2013, as well as our non-operated activity within Encana. In all, it is shaping up to be a busy and exciting time in the TMS during the summer and into the fall of 2013.

Thanks, Gil. As Gil stated, we continued to be optimistic about the potential of the TMS as accumulative production from the top 3 wells in the field continues to compare well with the Bakken and Eagle Ford, and costs are trending down as expected.

As we stated in our release, our operated Crosby well continues to produce above our 800,000 BOE-type curve with cumulative production of approximately 75,000 barrels equivalent at 91% oil over a 3-month period. We've recently run tubing, which we believe will help maximize production going forward prior to installing an artificial lift. Current rate of the Crosby is approximately 700 barrels equivalent per day, and we are receiving LLS pricing less $2 a barrel or approximately $105 a barrel currently.

The high BTU gas is also generating high natural gas liquid yield, which has been processed and sold on location. We are participating with EnCana for a 12% interest in the completion of the Ash 31-1 and 31-2 wells, with the 31 #2 producing for approximately 2 weeks with a 24-hour peak rate to date of 730 barrels equivalent per day, with 4% of the frac fluid recovered at a production mix of 2/3 frac fluid, 1/3 oil.

As a comparison, the Crosby well reached peak rate in about 7 days and was producing, at that time, approximately 2/3 of oil and 1/3 frac fluid. This is the well in which EnCana pumped a million pounds of proppant and 29,000 barrels of frac fluid per stage or more than double the amount of proppant in fluid of any previous well.

As we have said before, the more than double the amount of frac fluid pumped on this well will change the flowback profile, as compared to the other wells completed in the field, and we will need to wait to understand what the ultimate peak rate will be and whether the shape of the curve will be flatter due to more proppant as compared with the other frac jobs.

Very importantly, however, the Ash 31-2 landed above the rubble zone or primary zone of wellbore and stability, and we are encouraged that the well appears to have stimulated the entire TMS, which will help us on our cost reduction efforts going forward.

The Ash 31-1 well is still in completion phase with the finishing operation of coil tubing continuing. We have participated with EnCana on 2 development wells, the Anderson 17 #2 and 17 #3 wells, both of which we own a 7% working interest. Both wells have reduced drilling days and cost versus previous wells. The latest well, the 17 #3, was drilled with a 7,400-foot lateral in 42 days, which is well ahead of our drilling days and cost estimate currently for a 7,400-foot lateral. We expect both of these wells to be completed within 45 days.

We have spud, as Gil said, our Smith 5-29-1 well in Amite County Mississippi, in which we own an 88% working interest. We are planning for an approximate 6,500-foot lateral with a Crosby-style frac design and our AFE is approximately $13 million. We intend to drill the Smith well similar to the Anderson 17 #3 well by landing the lateral above the rubble zone, although with the slightly shorter lateral which, we think, gives us real chance of driving down costs. After the Smith, we have 2 additional operated wells planned through the end of the year.

And finally, our plan and focus in the Tuscaloosa Marine Shale is to duplicate the success of our Crosby well with our upcoming operated wells, and continue the recent improvement in total well costs. And in doing so, unlock tremendous value in the play and for our shareholders.

Question-and-Answer Session
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
Yes. I'm just trying to get a sense of what that Ash well costs came in at?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Leo, we like the results -- this is Gil, sorry. We like the results that we're seeing right now because we've got such a relatively minor interest and it's -- an EnCana operated well. I think we'd prefer to defer to them. But I will say that the number that we're looking at are within the range of where we're currently AFE-ing our Smith well.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division
Okay. But you guys expected cost savings for wells landed above the rubble zone, though. I guess are you baking that in to your estimate on the Smith well?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Yes. Leo, this is Rob. We think we can perhaps shave some additional time. I think we budgeted 46 days, 44 to 46 days on the Smith well, so if we can drill this well a little bit or on schedule as to how EnCana drilled the Anderson 17 #3 well, they drilled it in 42 days, and that was a 7,400-foot lateral. So there's some room for improvement, but it's based on basically, without any additional efficiencies gained. So we have some room for improvement on the well.
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
And Leo, this is Gil. I think -- we suggest people think of this, in a one-off well, is about $13 million of well, it might be a little less, it might be a little more, but roughly $13 million. And we believe when the dust settles here on the recent couple of wells that they'll come in at about that range.

Michael Kelly - Global Hunter Securities, LLC, Research Division
Given that you're still flowing 2/3 frac fluid from this Ash well, I'd love for you to talk about your expectations for what the ultimate max IP rate from the well could come in at? And really, just kind of interested in the timing of it and what factors could cause its come in? It looked like the Crosby could stay around current levels.
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, that's a difficult one. Lots of frac fluid still continuing to come back. And so our question would be how long it would take before they finally got those frac fluids down enough that the oil volume does have a chance to continue to climb, and how much near-term reservoir energy may have been lost in the process? So we can't say that it won't continue to grow [indiscernible] or not, because it will continue to grow in terms of well volumes. What we feel pretty confident about is, given everything we've seen so far, the Crosby and the Crosby-style frac is clearly the way to go until we've proven otherwise. So that's what you'll see us do in the near term.
Michael Kelly - Global Hunter Securities, LLC, Research Division
Okay. And my follow-up. Liquidity has much improved, close to $110 million preferred stock offering. But I'd still like to gauge your temperature on a potential TMS JV, where do you stand there?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Yes. I think the position, Mike, is really the same as it has been. We have expressed an interest and had some informal conversations with people that might have a like mind with us that would be kind of financing related. As we've said, we do not expect to see a large, across-the-board joint venture with a strategic partner that would happen this year. It might happen next year, but not this year. And so in the interim, we are interested in talking with some parties about perhaps some sort of more financial type transaction at the property level.

John Freeman - Raymond James & Associates, Inc., Research Division
I know that in the past, Gil, you had mentioned that the key determinant between a lot of these wells, whether they've been good or bad, has been being able to land in that bottom sort of 20, 25 feet of the TMS. And given -- I get it that it's early, it's tough to read too much into those Ash wells especially with all the different things they did on the completion side. But was there anything with them going above the rubble zone that would appear that maybe they weren't able to get in that lower portion of the formation?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
That's a great question, John. And the simple answer is no. We would have frankly preferred that one of the Ash wells had been completed in a Crosby-style frac, they were not. So that is what it is. But the fact that it's up around 750 barrels a day pretty well tells us that the full section got stimulated, albeit impacted, by the increased water volumes. So -- and I think it's important to remember that the delta here between the lower landing target and the upper landing target is really only about 25 feet of difference. So we feel pretty comfortable that, that whole section, including all the way down to the base of the TMS, is going to get stimulated with that upper landing target.
John Freeman - Raymond James & Associates, Inc., Research Division
Okay. And then last question for me. On the Smith well, since it sounds like you want to try and do, on the completion side, as similar as you can with the Crosby despite the fact that it will obviously be above the rubble zone. But when you talk about having a shorter lateral, maybe if you could just sort of clarify a little bit more, how much shorter and what's -- it's purely a cost decision, and anything else driving that?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Yes. Hey, John, this is Rob. But really, we're targeting the Crosby lateral link, which was 6,700 feet, we've rounded it to 6,500. If things are going really well like the Anderson 17 #3 well, we may go until that bit runs out and get a little bit longer lateral. But that's just a target lateral link, and to try to replicate again what we've done on the Crosby, same frac design, same lateral link, and reduce well costs by landing above the rubble zone. That's the plan. But if things going well, you could see us add to our lateral link.

Pearce W. Hammond - Simmons & Company International, Research Division
Great. And then with the state of Mississippi, can you outline sort of any policy initiatives from the State whereby they're trying to help stimulate the growth of the Tuscaloosa Marine Shale? And then as well as -- just in general sort of the regulatory and the government response there in the state?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Sure. Really, it's a good story all the way around, Pearce. Very recently, the legislature of Mississippi passed and the governor signed a severance tax abatement for the state of Mississippi, which reduces the severance tax from 6% to 1.3% for the initial 30 months of production or until payout, whichever occurs first. That's a very significant improvement in the economics of the early-time wells. So that's now a law in the state of Mississippi. The Mississippi Oil and Gas Board has been extremely helpful and flexible in working with the industry to facilitate development, forming the units, permits, et cetera.
So the state of Mississippi is very much focused on the Tuscaloosa Marine Shale, very much hoping and expecting it to become a full-fledged play with lots of activity that can bring business in and, in particular, jobs back to the state of Mississippi.

Joseph D. Allman - JP Morgan Chase & Co, Research Division
Hey, Gil, you mentioned that some of the recent TMS wells are running around $13 million, what are you including in costs in that $13 million?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Well, everything, Joe. That's drilled, frac-ed, completed and producing the tanks [ph].
Joseph D. Allman - JP Morgan Chase & Co, Research Division
Okay. And did that include facilities as well or no, you're excluding facilities there?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
No, there would be some additional facility costs probably in the rate [ph] of about $500,000 of facility cost.
Joseph D. Allman - JP Morgan Chase & Co, Research Division
Perfect. And then in terms of the Ash well, the one that's producing 730 barrels a day equivalent, what's your conclusion on that well? I know it's a bit of a shorter lateral than your Crosby well, but I think there was more frac fluid, more profit per stage. It doesn't seem to be as good as the well as your Crosby well, could you just talk about your conclusions there?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Yes. Joe, I think as we've said, our early analysis is that the incremental frac size, and in particular, the addition of the frac fluid that would have to be pumped, as Rob said, 29,000 barrels is impeding and impacting the well's ability to flow at the same lind of oil rates and pressures that we saw from the Crosby well. It initially was about 2/3 frac fluid, 1/3 crude oil when it first got to the -- its initial rate. It continues to be at about that ratio. And as a benchmark, our Crosby well was almost exactly the opposite, about 2/3 crude oil and 1/3 frac fluid. So we're in a wait and see pattern, as Rob said in his comments, it very well may be, but longer-term, that's the right thing. It doesn't result in the bigger IP, but it may ultimately produce more oil with a flatter curve and bigger EUR. We've just -- it's just too early to say. But clearly, as we look at the performance of the Crosby against every other well in the play, including the Ash, until proven otherwise, that's the right method and the right frac technique.
Joseph D. Allman - JP Morgan Chase & Co, Research Division
Great. And then just on a different topic. In terms of just financing plans and monetization plans, I know you've talked about the TMS JV earlier and you're talking about it being more finance related, if you could just maybe elaborate on that some more? But also, what are some additional financing plans and monetization plans that you're contemplating?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Yes. Joe, this is Rob. One of the things we've talked about in -- at conferences is the ability to kind of carve off a portion of the TMS with a financing partner, private equity-backed, to kind of almost bridge the gap in funding for the TMS to a point where you drill several additional wells, you help derisk the acreage, you get your well costs down, you've proved what the economics are, and at that point, then you start talking about more strategic long-term larger-type transactions. That's still something of interest to us and something that we still are focused on. Alternative financings, obviously, there are several. We still have the Beckville/Minden field, which is a Cotton Valley field in East Texas. It's 25% liquids, predominantly NGLs. It's held by production, but it's a field that's likely not going to get an allocation of capital as long as we have the Haynesville, which carries a better rate of return. So that's still something in our back pocket if we want to do that. However, that property would be worth more with a little bit higher gas price, and that's we've held off on doing anything to date. We can also tack on to the preferred at some point down the future, in the future, if we choose to go that route. And then as to -- we have some convertible notes that are pullable on October 14. Our game plan is to get some clarity by the end of the year as to how we'd take those out, whether we take down a portion of it in the Minden extend, or whether we take it all out or we push it all out for additional time. So all of those things are coming down the road over the next 6 to 9 months. But as we sit here right now with ample liquidity, it's really focused on execution and we have some exciting well data coming out of the next 3 months or so.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
Hey, on the Ash well, just to clarify something. Rob, you said you think you're getting contribution from the whole TMS section and some of that was based on just the 730 BOEs per day of production. Has there been any microseismic, either on that well or offsetting wells, whereby offsetting operators to suggest that if you go in above that zone that you are getting contribution or you just basing that off of rate?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Yes. Good question, Ron. And you're right on. There is microseismic that's been shot from other operators. And in fact, it does show quite a bit of frac vertical growth, both up and down. In fact, some of the other operators certainly had been convinced of that for quite some time. We just wanted to get a well result that indicated, based on early flowback, that we are able to stimulate the entire section. And it does support what we've seen previously on microseismic, which is very good growth up and down.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
And is it -- I mean, you said that you plan on probably doing the Davis above the rubble zone and absent something that happens with the results to change that, is -- would that likely be the plan going forward? And how much does above the rubble zone save in time and/or well cost versus what -- targeting the well below?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Yes, Ron. I will tell you that we will remain fluid and nimble. If we see different data suggesting that we should still land below it, we would certainly amend our plans. But as we sit here right now, based on the last answer that I gave, it certainly feels like we're adequately simulating above and below. And frankly, what we were really pleased to see from EnCana when they were drilling the Anderson 17 #3 well, they were making 1,000 feet a day out in the lateral several days, and that's more than twice the rate of penetration that we drilled below the rubble zone mainly because we had a 10-foot window below it and had to slide drill good bit. And we have a, probably, 20-, 25-foot window above the rubble zone, which gives you the ability to push your rate of penetration a little bit more aggressively. So it's all about target windows. Another firm drilled the TMS well up in the middle of the section and they had a 50-foot window by our estimates. And, well, when you can do that, you can do what we do in the Eagle Ford, which is we've made as much as 4,000 feet, of lateral feet, on a given day. So it's all about your targets, it's all about the ability to rotate drill and instead of slide drill. And let us get a few wells down under our belt, above the rubble zone. But right now, I'm pretty encouraged by what we're seeing, by landing there.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division
Both those Anderson wells are drilled above the rubble zone and how are those going to be completed?
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. The Anderson 17-2 is below the rubble zone, the Anderson 17-3 is above the rubble zone, so they're opposite. EnCana is obviously the operator, so we'll defer to them on the exact final completion. But in communications with them, we believe, as of this morning, they do plan to sort of -- to complete both those wells very similar to the Crosby.
Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division
Okay. And you'd mentioned that based on the results of the Ash well, you think you're pretty confident that you can frac through that rubble zone, you may have some microseismic, maybe a suggest as well. Any concern that over time that, that might be an area that would be difficult to keep propped open or too early to tell? Or do you feel confident that you can keep that propped open there?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Yes. Thanks, Mike, good question. No real concerns from us about being able to keep it propped open. We only are looking at about a 25-foot difference, as I said, between the 2 landing targets as we look at the rock makeup and the mineralogy, very little difference between the 2, other than we do have this one very highly fractured, naturally fractured, rubble zone in between us. So I think our biggest concern was just not that we didn't think it absolutely made sense that you should be able to get it fully stimulated, we absolutely did think that was the case, but until we had seen the well that was producing commercial economic volumes, we thought it's just more prudent to stay in that lower target. Rob mentioned the microseismic we've seen. we've seen 250 to 300 feet of overall top-to-bottom stimulation impressions from the microseismic. So again, even the upper landing zone is still in the bottom half of the overall TMS section, so we're getting increasingly comfortable with that. And when you look at the improved drilling performance of the Anderson 17-3, as Rob described, we just think it's -- it makes sense and is very prudent to move to that as the target with our Smith well.

Dan McSpirit - BMO Capital Markets U.S.
Can you outline the timing of the Smith well completion, and maybe with it results knowing that I guess the 44-day drill time? And maybe the same question for other operated wells planned for later this year?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Yes. I think we are targeting kind of 75 to 90 days depending on when we can get the frac in place. But certainly 30 days from TD, which is the frac-ing the wells for 90 days spud to sales is certainly a real possibility. We are drilling out from under the surface casing, I guess today, probably 4,000 feet or so. It takes about 15 days roughly to hit through vertical depth and run your intermediate casings. And then from there, it just depends on how long it takes to get the lateral drilled. So I would say, probably 75 days, 60 to 75 days from now, at least a time to start looking.
Dan McSpirit - BMO Capital Markets U.S.
Okay, very good. And as a follow-up, I recognize that it's only May 2013, but can you sketch for us what activity in the TMS in 2014 could look like, maybe from CapEx allocation to rigs working to maybe operated wells drilled ?
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. You're right, it is little early. And obviously, it's pretty dependant [ph] on the success that we've seen in the second half of this year in the TMS. But as we currently view the play, I think you can think about us as significantly increasing our allocation, at least preliminarily in our mind for the TMS for 2014. And probably, I would say, conservatively, from -- up from a $50 million allocation to $100 million allocation next year. And depending on the robustness of the results throughout this year, perhaps even higher than that.
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
And Dan, this is Rob, I might add. We have great flexibility to just flip our allocation between the Eagle Ford and TMS if we continue to see equal or greater rates of return in the TMS. Because of our acreage position in the Eagle Ford, we can just switch that and allocate 2/3 oil-directed activity to the TMS with 1/3 in the Eagle Ford, and still maintain our core Eagle Ford position.
Dan McSpirit - BMO Capital Markets U.S.
Okay, great. And then one last one. Sticking with the TMS, whether you decide to land the lateral above or below the rubble zone going forward, would it uniformly apply to all of the leasehold or would 1 method work better in different parts of the play?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Yes, good question, Dan. I think we would believe that it's more across the play. We don't know -- we don't have enough data points to know whether or not the "rubblelized zone" is present throughout the entire acreage block. We're looking -- our acreage spans almost 120 miles from one end to the other, so very likely, that it may not cover that entire area. But we would be looking at somewhat of a slightly higher target to avoid the potential presence of that in the wells going forward.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division
Just following up on Dan's questions on the TMS timing. Once we get past, I guess, these several wells that EnCana's currently drilling or completing, what do you think industry activity looks like for the second half of the year based on current permits? What you hear on the ground, et cetera?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Yes. Richard, this is Rob. A lot of that depends -- I think, from what we understand, EnCana has kind of a budgeting meeting in June and we'll just have to see what their decision might be. We had a development committee meeting here a month ago or so. And their thought was they would remain active in the second half, but waiting to see how many rigs would be running in the play. So that's really up to them as to how much capital they plan to allocate. With our 1 rig running in the second half of the year, we're certainly going to kind of accelerate our operated activity, and we do you plan to participate with EnCana in a number of, as a non-op, in a number of their wells if they continue to remain as active or more active in that second half of the year. Other than that, I'm not familiar with what EOG's plans are, or [indiscernible] plans are, we'll just have to obviously ask them as to their plans.
Richard M. Tullis - Capital One Southcoast, Inc., Research Division
Okay. And then just lastly, what's the current LOE OpEx requirements for the TMS wells?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Well, we're baking in, in absence of a whole lot of data, we're baking in what we do in the Eagle Ford, which is -- I think it's averaging, call it $1 per M if you want to get close, or maybe $1.20 on the high end. And the way we model it is there's a fixed cost and then a variable cost. And I think our fixed is 10,000 a month plus variable of $3.50 or $4 a barrel. But it equates back to $1, $1.25 an M, something like that.

Unknown Analyst
Got you. And I jumped on late, so I may missed this. But in terms of the Ash 31 H1 well, when is that -- when should we start seeing some flowback from that?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Well, as we said, they've had a piece of coil tubing that got stuck in the wellbore when they were drilling out the plugs after the frac. They've been on that for quite a while. It's hard to say exactly when that may be done, but it looks like they're getting close to a point of wanting to flow the well back. So can't say exactly without -- our expectations will be the next 2 to 3 weeks.
Unknown Analyst
And then I guess on the Smith well, in terms of the frac-ing procedure, you're looking to do more of the larger fracs as you did on the Ash or what's kind of the plan there?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Well, as I think I've said several times during the call, we plan to do a frac very similar, if not identical, to what we've done on our Crosby well.

Michael Kelly - Global Hunter Securities, LLC, Research Division
You mentioned a few times that these EnCana super pump frac jobs really aren't goosing up your IP rates, but it could result in a decline curve that is just not as steep as what you'd see with -- not as much profit used. I'm just curious, if you look at the Weyerhaeuser 60H-1 well, which did have quite a bit of profit and putting in 750,000 pounds per stage, you got 2 months of history there, are you seeing any evidence that the second month -- that the decline is not as steep as your other wells drilled in the play?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
That's a good question, Mike, and I would say, very likely, yes. Didn't see as high of an IP, but it doesn't seem to be declining quite at the rate we were seeing from some of the other wells. Again 1 or 2 months doesn't exactly make the entire picture. So we would still remain cautious about pumping that much fluid and proppant at this juncture. But time will tell.

David Snow
What was the well -- the Crosby well cost?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Dave, this is Gil. We've not given the specific numbers. What we have said is that, that well had a good bit of science in it. We drilled a vertical pilot hole to conventional core in it. There's a lot of open hole evaluation. If you normalize that piece out as best we can, we're coming up with about a normalized 45-day cycle time from spud to when we PDP in the lateral. And if that number be -- we're fairly consistent with what we've seen and the way we're modeling these wells going forward. Hopefully, as Rob mentioned, what we've seen in these last couple of wells, particularly the Anderson 17-3, we have a shot at improving upon that maybe even [indiscernible] materially.
David Snow
Okay. And is the Smith above the rubble or is it the next one after the Smith above the rubble?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
We're landing above the rubble on the Smith well.
David Snow
Okay. And how much do think you'll save in the -- being above the rubble in cost?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Yes. David, this is Rob. Well, we just -- we've cited that they were drilling in the lateral at twice the rate as to what we were drilling below the rubble zone. So for every day you can shave, it's about $100,000 of savings. But until we have that under our belt, everything's hypothetical. And we just -- we're going to try to replicate what EnCana did on drilling the well and then try to replicate what we did on completing the Crosby well. If that's the case, we have a real shot at very good economics on the wellbore.
David Snow
And the Ash had a slickwater in addition to everything else as compared to gel hybrid. Which one are you using, the gel hybrid or the slickwater?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
We're going to do -- we're going to replicate exactly what we did on the Crosby well, which was a hybrid frac.
David Snow
Okay. Is the slickwater taking off a lot more volume and could that have been another variable that obscure seeing results in this...
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Yes. David, it's twice the amount of fluid volume than what we've pumped on the Crosby and twice the amount of fluid is obviously going to take a lot longer to produce off.
David Snow
Okay. I see your Crosby wells kind of flattened out at 700 barrels a day, it was doing that at 2 months on your curve, is this a good omen or is it just as a blip in the curve?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Well, we were ran tubing, which is obviously helping to lift the liquids. And so give us some more time, we're going to continue to update all of our curves, including the Crosby. And certainly, extremely optimistic with what we're seeing. And I think when you see what the cumulative production has done compared to all these other plays, even for Bakken, in particular, it's awfully impressive. So yes, we're excited about what we're seeing and just need to see some more history.
David Snow
Why do you think they use the slickwater instead of gel hybrid?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Yes. David, this is Gil. They're experimenting around and trying different techniques to see what works the best.
David Snow
Well, they buried so many things at once, it's really hard to get a clear answer as to what's going on, I guess, isn't it?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
We understand that.

Chad Mabry
Just following up on one of Gil's comments. Just curious if you could help us, how much of your TMS position do you feel is delineated a this point in that kind of that Emmet, Wilkinson County area?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Yes. I think, if you take our acreage position that's in Amite and Wilkinson, in those 2 areas, maybe pick up a little bit in -- right along the Mississippi-Louisiana border, you're going to get about 60,000 to 70,000 acres of our 135,000 acres. We have a big position. A little bit west, right along the Mississippi River. But in Louisiana, Southern Concordia, it's about a little over 40,000 acres that we've not drilled on yet. We bought the acreage because of older vertical wells that pass right through the TMS and we could get a pretty good read on the geology over there, so we remain very, very optimistic about that but have not drilled a well there yet.
Chad Mabry
And any plans over there? Should we assume that most the near-term activity is going to be focused more still on mid-county area?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Yes. Clearly, that would be a '14 event. We've got plenty on our plate right where we are, and it makes perfectly good sense to us to be a little more prudent and just stay within that Amite Wilkinson County area for the near term.

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