Monday, December 31, 2012

Monday, December 24, 2012

Merry Christmas

Merry Christmas Tuscaloosa Trenders.  May 2013 bring the TMS some great success!

Anybody want to guess what rig this is?

Thursday, December 20, 2012

EOG Dupuy Land Co. 20H-1 - Initial Potential

All eyes have been on Avoyelles Parish and EOG's first horizontal TMS test, the Dupuy Land Co. 20H-1.  Rumors have been rampant the past ten days with a wide range of rumored flow rates.  I've been reluctant to make a post until accurate rates were confirmed.  From what I understand, an initial potential of 656 bopd will be released by the state.  The well is choked back and has produced 10,400 barrels over 23 days (Average: 452 bopd).  The IP30 will likely fall short of my estimate but when the choke is increased, this well should flow at an attractive rate.

Tuesday, December 4, 2012

TMS Production Updates

Here are some updated production charts and observations:
-All of the wells indicate that their curves are flattening; Some wells increased due to an increase in choke.
-Monthly decline rates are consistent
-Devon Beech Grove 68H-1: while a low rate producer, the well at 12 months has declined 77% which is in the "Eagle Ford" range.
-Cumulatives: Anderson 17H-1 65 MBO in 4.5 months; Anderson 18H-1 77 MBO in 4.5 months

Monday, December 3, 2012

Dupuy Estimate Update

With a confirmed number of successful stages in the Dupuy well, I've updated my estimate.  I believe that this well could produce over 700 boepd for thirty days.

Prior estimate with charts:

Sunday, December 2, 2012

Capital One Southcoast 2012 Energy Conference

I will be presenting on the Tuscaloosa Marine Shale at the Capital One Southcoast 2012 Energy Conference in New Orleans this Thursday.


Thursday, November 29, 2012

Tom & The TMS

Tom Petty once said that "the waiting is the hardest part".  When it comes to drilling wells, they never drill as fast as you like.  Someone once said that "patience is a virtue".  The virtue of the TMSers has been tested this past six weeks.

EOG is once again raising the bar with their drilling pace on the Gauthier 14H-1.  They will have the play sub-$10M by mid 2013 if not sooner.  The Dupuy results should be forthcoming.  I understand that 19 of the 20 stages were successful.

TMS well statuses

Thursday, November 22, 2012

Happy Thanksgiving

Turkey distribution at Emmaus House.
Happy Thanksgiving Tuscaloosa Trenders!  Thank you for the recent donations.  You funded 180 turkeys that were given out to Hurricane Sandy folks at Emmaus House in Harlem yesterday.

It's a great time of year to be generous.
Donate today:

Results from the Dupuy and Denkmann should be forthcoming in the next few weeks.

Wednesday, November 14, 2012

Halcon Hits Their First Challenge

Based on the Scout Report on SONRIS, it appears that Halcon had issues kicking off their lateral in the Broadway H-1 well after drilling a pilot hole through the TMS and taking a conventional core.  It appears that they had to go back up the hole and kickoff at 3568' and start a new hole.
Source: SONRIS

Thursday, November 8, 2012

Goodrich Petroleum - Q3 Earnings Call

Goodrich's earnings call had some really good details regarding the TMS.  Here are the TMS highlights:

The closing of the divestiture of the South Henderson field provides a meaningful boost to our liquidity, and we will consider additional non-core asset sales and/or joint ventures in the Tuscaloosa Marine Shale or Pearsall Shale at the appropriate time to ensure we maintain ample liquidity and can again execute an aggressive oil-directed drilling program in 2013.

While we previously expected to rotate 1 Eagle Ford rig to the Tuscaloosa Marine Shale during the fourth quarter, we now plan to maintain 2 rigs running in the Eagle Ford into and through 2013.

In the Tuscaloosa Marine Shale, where we have acquired approximately 134,000 net acres, we continue to make progress in de-risking and delineating the play. The drilling issues associated with this play and, therefore, higher well cost experienced today have primarily been associated with wellbore stability issues or a well-defined, highly, naturally fractured geologic interval of approximately 10 feet within the TMS has had a tendency to slough or cave in to the lateral wellbore, especially when this wellbore is traversed at a high angle. There are a number of potential remedies, including: one, traversing the interval at a lower or a more vertical angle; two, drilling through the naturally fractured zone and setting intermediate casing over the interval; or three, landing the horizontal lateral above the fractured interval.

Our non-operated Ash 31H well has recently been drilled and successfully landed above the natural fractured interval. The well is drilled with a lateral length of approximately 6,600 feet through the TMS without significant drilling-related issues. Production casing has been set, and the well is now waiting on completion. Eliminating the wellbore stability issues and drilling issues, as it appears we have done on the Ash 31H, will result in meaningfully lower completed well cost in the TMS, and we are encouraged by these wells' drilling performance.

On the performance side, we remain very encouraged with well performance to date with the oldest grassroots TMS completion now having been online and producing just over 11 months and 2 longer laterals having produced just over 5 months, including the Anderson 17H, in which we have a 7% working interest, which is producing over 300 barrels a day after 5 months online. We are continuing our development of the TMS at a measured pace, with approximately $14 million of net capital expenditures invested in the first 9 months of this year or approximately 8% of total drilling and development CapEx through the third quarter. Production for these wells will begin to impact net oil volumes in the fourth quarter and as we enter 2013.

In addition, we are expecting an additional 4 to 5 Tuscaloosa Marine Shales to be completed over the next 2 to 3 months, which will provide important incremental data points and help with our evolving knowledge and evaluation of the play.

In the Tuscaloosa Marine Shale trend, we have successfully frac-ed 12 stages over an approximate 4,000-foot lateral on the Denkmann 33 #1 well, our first operated well in the field, in which we own a 75% interest. Oil back has been delayed due to the necessity to repair 1 popped casing connection near the last set of perforations on the last frac stage, which stage was successfully pumped. Other than the 1 popped casing connection, the casing is in good shape, with no anticipated issues to reaching our target rate of production once we patched the connection. This is obviously not a typical occurrence, but we've experienced this before in a different area and are confident we will get it patched in the short time frame, at which time, we will then drill out the plugs, run tubing and commit flowback, with production results expected in a few weeks.

We've also participated for a non-operated interest in the Joe Jackson 4H #2 well for 25% interest, which is currently flowing back, and the Ash 31 #1 well for a 19% interest, which is being drilled and is -- which has been drilled and is in completion phase. Although the Ash 31 1 won't be completed until the Ash 31 #2 well is drilled from the same pad. As Gil described, we were very pleased with how the Ash 31 #1 well drilled, which should materially reduce well cost going forward.

We are currently drilling our Crosby 12 #1 well in Wilkinson County, where we own a 50% working interest. We have drilled, cored and logged the vertical portion of the well and are in the process of kicking off to drill a projected lateral of approximately 7,000 feet. We expect to run an additional 100 feet of casing to get the rubble zone behind pipe in the Crosby well. We have identified 14 potential units that could be drilled in 2013, pending continued success in the TMS, with the Huff 10 #1 well in Amite County, Mississippi, our next operating well after the Crosby. We plan to continue to run 1 rig in the play through the first quarter of next year, at which time, we'll make a decision on whether to accelerate development and bring in a partner.

In closing, the Eagle Ford will continue to drive our oil volume growth through 2013, with an improving gas environment and tremendous optionality on the TMS. Our improved efficiency in reducing drill times and well costs in the Eagle Ford is consistent with every other play we fit in, whether it was the Haynesville Shale or Cotton Valley before that, and we are confident the same will occur in the TMS. And, in fact, the Ash 31 1 is an initial step in that direction. We remain encouraged in the resource potential of the TMS and our ability, along with the other companies in the play, to reduce well costs. And as a reminder, the TMS enjoys some inherent advantages to other oil plays, and that it is 94% Louisiana Light Sweet oil, with lower royalty burdens and favorable severance tax structure. Although we continue to only allocate a small portion of our CapEx budget to the TMS, the upside remains tremendous for the company, if proven up over the next 6 months.

Thank you, Jan. As I said, we remain encouraged by the performance of the initial wells in the Tuscaloosa Marine Shale and are confident we are moving quickly towards resolving the early time drilling issues. And we believe the next 6 months will be very important in demonstrating the plays' economic potential. Our phase of development in the TMS will be dictated by results in the field. And as we continue with the prudent de-risking of the play, we will continue with our execution of oil-directed drilling and oil volume production growth in the Eagle Ford Shale.

For the quarter, we spent 77% or $44.3 million of our capital in the Eagle Ford, where we have 2 rigs running, and 19% or $10.9 million in the Tuscaloosa, with a combination of drilling and completion expenditures associated with 2 non-operated wells and 1 operated well of $9.5 million and leasehold acquisition of $1.4 million.

For the 9 months of 2012, we spent approximately $14 million on drilling and completion expenditures in the TMS or 8% of the total drilling CapEx budget. We will release our 23rd CapEx budget in December, but we are likely to continue with the 2-rig program in the Eagle Ford and 1 rig in the Tuscaloosa for the first quarter of 2013, with a decision at that time of whether to bring in a partner and accelerate development in the play.
Michael Kelly
 - Global Hunter Securities, LLC, Research Division
Hoping to get some more color on the sloughing issue. After you've successfully drilled this Ash well, do you feel like you've kind of nipped this issue in the bud or is it too early to tell? And then I was hoping you could quantify what the decreased well costs really means? When you say that going forward, if this Ash-type completion is really kind of a new standard, what does that mean?

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 I'm not sure we would classify nipping it in the bud. But as we said, we're certainly very encouraged by that, and it is one of the clear remedies for the sloughing of or caving in problem from this naturally fractured zone. As Rob mentioned in the call, on the Crosby, we currently plan to try another alternative, which is to get through it in a little bit more vertical angle, get it off -- get it behind casing and continue with our landing of the lateral down in the bottom, 15 to 20 feet of the TMS. So I think right now, we're going to look at a couple of different ways. We'll see what impact, if at all, there is on the performance of the wells. And I think either one of them is a very viable option. It really does not -- either one do too much to the overall well cost. In terms of cost, we've talked about a number of $12 million to $13 million. The drilling-related issues, as we look not just at our experiences and operator but the other companies, have obviously been all over the map in terms of how much time and effort is spent having to wring the wellbores out, search laid out the incremental cuttings that are sloughing off into the wells. So that's really all over the map, but clearly, we've heard numbers of $14 million, $15 million, $16 million of total well cost. And we think that by eliminating the sloughing, you can certainly get it back down in the range of certainly $12 million. Of course, that's dependent on the lateral length that would be for about a 7,500-foot lateral, with something on the order of about 25 stages. So shorter lateral, shorter frac stages, obviously, you could drive the cost down lower than that.

Michael Kelly - Global Hunter Securities, LLC, Research Division
Okay. I appreciate that color. Definitely, costs are the hot topic with the TMS. And just to clarify that, $12 million is really what you think you could drill that 7,500-foot lateral today? And going maybe a year out here as you progress in the play, some operators have said that they need to get well cost down to $10 million a well to see this play really viable. Just wanted to get your thoughts if you agree with that. Or do you even think that pushing them down another 20% plus is possible?

Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Yes, I would say that we certainly see a pathway towards getting cost down to $10 million. It would include pad drilling and leveraging off of that. It would require some incremental infrastructure to come into that part of the world. And the second part of that question is really we're all wondering around, where the EURs land, we have not published the range of EURs yet. But I think if you certainly get anywhere near what EnCana has been talking about, it will stand up very robustly even at $12 million to $13 million. So we're not ready to publish EURs. But clearly, that's the big driver, and the economics of the play is where the EUR is going to land. And we certainly think 500,000 to 600,000 barrels clearly stand up easily to $12 million to $13 million.

Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
And Mike, this is Rob. I might have another [indiscernible] obviously comes from the frac cost, and we've already seen improvement from original frac bids to current. So a combination of reduce the drill days and better efficiencies, more equipment in the market and continuing reduction in frac cost are really the primary drivers.

Michael Kelly - Global Hunter Securities, LLC, Research Division
Okay. Great. And one more, if I can sneak in here. I'll jump back. You mentioned a couple of times in the prepared remarks that you'd be contemplating JVs in both the Pearsall and the TMS, like you pegged TMS JV at the end of Q1 possibly after you've really assessed how the play has been going so far. Just hoping you'd give a little more color on that, if you actually have started the process there on the JV side on either basin.

Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Yes, this is Gil. We have not started the process on either one, and we're giving our best guess as to when we think those plays will be in a mature enough place to extract the kind of value we would be looking for in terms of a joint venture. So those are just estimates. It really will depend on the evolution of the 2 plays and where we are. But we certainly think somewhere in the first half of next year, if not roughly around the end of the first quarter, we feel like it seems to be optimal.

Ronald E. Mills
 - Johnson Rice & Company, L.L.C., Research Division
Okay. And to move over to the Denkmann, Rob, I think you said that you still think you can achieve your anticipated production rates despite having 12 successful frac stages. Can you walk through what happened from not just the lateral length going from 7,000 to 4,000 feet, but with that lateral length coming down, did you get all stages off that you were able to get done? And how did you manage the proppant component of the completion and the benefits of starting through tubing immediately and how that can help from a production standpoint?

Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Sure. I mean, we -- yes, we were initially targeting a longer lateral. The rubble zone and the sloughing clearly caused us not to have to -- not to be able to get the full lateral length that we desired. Ultimately, when running production casing, we didn't get all the way down to what we had hoped to get to but felt comfortable with the 4,000-foot lateral and 12-stage frac, allowing us enough to get our target initial rates. And obviously, running tubing allows you to control the flowback, perhaps adjust chokes quicker and flatten decline curves, which we've said before is a goal of this well in our operation. So we feel like we -- obviously, the sloughing caused us to keep from getting the full length, but we certainly feel like we have an adequate lateral length. What we think is you can hit your initial rates. And, for example, that -- the Pearsall well we talked about was 3,000 to 3,500-foot long laterals, yet they achieved 1,400, 1,800 barrels a day. So you can flow the wells back at a higher rate. It's really more impactful on the EURs, in our opinion. The longer the lateral, the more feed in you get from more rock, the higher the EURs. But in this case, we feel like we can achieve our targeted initial rates.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
Okay, great. And lastly on the TMS, the production impact that you mentioned versus the exit rate. It sounds like what the last contribution is, is just the timing of both the Crosby and the first Ash well. It sounds like both of those are more likely those combined with the second Ash well or more likely to be January-type completion, so impact in the first quarter. Am I reading that right or was there something else beyond just the South Henderson sale and the timing of the TMS?

Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
That's exactly it. It's -- you always circle dates on a calendar that are expected -- you're expected to commence frac-ing operations on and whether service provider is a bit late getting there due to a previous well. That's always somewhat of a risk. But we would say the material difference is, as you stated, at South Henderson and then the 2 TMS wells are really -- had we not have those delays and not sold the property, we would have been in excess of 5,000-barrel-a-day exit rate. So still pleased with kind of where we are, but those were the primary reasons for the reduction in exit rate.

Brian M. Corales
 - Howard Weil Incorporated, Research Division
Can you maybe just talk about the -- of the total well at TMS, how much -- what percent is completion versus drilling or of the first well you drilled or what you have seen with EnCana?

Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Yes, we're typically seeing kind of 40% drilling, 60% completion. It does depend on lateral length, and that's how you derive the frac cost, obviously, with a number of stages. But I think that would be a reasonable level to consider. If you look at spread rate, which is rig rate plus all the other goods and services charged on a daily basis, we typically run $90,000 to as much as $100,000 if you're -- depending on the equipment you're running in the well. So every day, you shave off of that. You could see as much as $100,000 of cost savings. And frankly, that's what we did in the Haynesville. We went from 40 to 30 days. Just the more we drilled, the easier it is to develop optimum drilling practices. We expect that to happen here again. So I think I would use that as a rule of thumb if we can take it from 42, 43 days to 32 days. We'll save about $1 million off of the expected well costs. And then as I said earlier, just once you prove up a play, just like we saw on the Eagle Ford, you're going to see increased competition with all service providers, and that will continue to drive down costs.

Brian M. Corales - Howard Weil Incorporated, Research Division
Okay. And can you maybe talk about, even if it's a non-op well, what not going in that rubble zone or, I guess, the difficult 10 feet, what that could save in a drilling days time?

Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Clearly, I think we talked about how much time we spent on the Denkmann, just dealing with washing and reaming due to sloughing. And no question, you're looking at 10 to 15 days. Just pencil how far out you are in the lateral and how many times you have to replace either drill bits or bottomhole assemblies or mud motors. Every time we came up while in the lateral, it went back down. We couldn't necessarily start making new hole, we had to clean and wash to get back to where we were. And that's the real drag time. The Ash well just didn't have the same experiences. And the concept was landing above that 1 zone. Obviously, it's better rock and we just didn't see the same type of sloughing.

William B. D. Butler
 - Stephens Inc., Research Division
Talk a little bit more about gas, the improving gas price environment in the wells that you guys are going to complete as a non-op. What do you all think? There's been some other Haynesville operators that have been really working to get well cost down and are claiming that they can get them down. There's $8.8 million and they can go to $8.5 million or possibly $8 million sort of on that Louisiana side. You guys, I think, have typically talked about $9 million as your midpoint. What do you think could happen next year in terms of without -- just with relative service capacity, et cetera, in this sort of $4 -- let's call it a $4 gas price environment. Could you guys achieve $8 million well cost there versus $9 million?

Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Yes, William, this is Gil. First, let me make it very, very clear. We are not drilling any new and don't have any plans to drill any new Haynesville shale gas wells either in the remainder of this year or in 2013, unless and until the gas market improves appreciably above where it is today. So what we have talked about is the 6 net wells that were drilled, most of which were drilled in late 2011 and have been sitting cased but uncompleted here for the balance of this year. And in conjunction with our joint venture partner in the TMS who operates the vast majority of those wells, they believe that it's prudent to move forward now with a completion to go ahead and complete those wells and bring those wells into production. So that's really all we're talking about for Goodrich in terms of gas. As to your more general question about drilling costs, we obviously keep a very close eye on Haynesville-related drilling costs. We would concur with your comments that costs have likely come down from the $9 million to $9.5 million range to probably the low $8 million range. We have drilled wells back a couple of years ago. It's low, it's just under $7 million. So under the right circumstances, we certainly see that is being achievable. I would say that, again, however, even with those kind of numbers for Goodrich, given the ongoing delineation of the TMS, the ongoing pad drilling strategy and all volume growth strategy in the Eagle Ford, it's unlikely you'll see us start moving rigs to gas-directed drilling unless natural gas prices make an appreciable move-up from where they are.

William B. D. Butler
 - Stephens Inc., Research Division
I mean, does that make the Buda sort of an asset that you all could monetize in, if it's not a near-term priority or just...

Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Potentially, William, but I think the bigger place for us would be in the Pearsall, more impactful, as well, of course, doing something, as we've talked all along, at the right time in the TMS.

Michael A. Hall
 - Robert W. Baird & Co. Incorporated, Research Division
I guess quickly on my end, just curious on maybe a little additional color on the decision to move the rig back to the Eagle Ford from what was allocated in the TMS. Is that earlier than you'd previously kind of thought? It was a bit earlier than I was thinking. And as you talked about, you can build up a decent amount of inventory, I would think, in terms of wells drilled in the Eagle Ford. Do you have -- particularly now 2 rigs, do you have the frac contracts in place to take that inventory? Or just any additional color on those decisions.

Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Yes, Michael, this is Gil. First, yes, you characterized it slightly wrong. We never moved it out. The anticipation was that we would move it out of the Eagle Ford and over to the TMS during the fourth quarter. And instead, it's just going to stay there. So it wasn't as if it left and it's coming back. It's just going to stay there. And we had contemplated all along that even if we did that temporarily by moving out of TMS, we would have another rig moving back into the Eagle Ford in early 2013, with the contemplation of running 2 rigs down there. So it's only a very short-term kind of change. And as Rob mentioned, because of delays that we saw in the Denkmann, which pushed the Crosby back, which pushed the Huff well back, then it makes sense for us to continue on with a little bit more prudent approach to the TMS to keep the CapEx down there and leave the rig in South Texas, with the idea that we'll move on down the road here a few more months and then consider bringing potentially another rig over into TMS as results gel a little bit more.

Michael A. Hall
 - Robert W. Baird & Co. Incorporated, Research Division
Got it. It's helpful. And then I guess just quickly jumping over to TMS. As it relates to landing the lateral above the slough zone, is there any -- are there any potential implications on the frac in terms of landing above that zone? I mean, is there -- I guess I'm just trying to think through like what are the potential risks around doing that. And like you said, you're evaluating a couple of other approaches to dealing with the slough zone. Just trying to think about the completion side of it as opposed to just the drilling side. Anything we got to keep in mind in that regard?

Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Sure, Michael. This is Gil. So our original landing target was approximately 15 to 20 feet off the bottom of the TMS. The fractured zone or rubblized zone is approximately 40 feet off the top of the TMS, and I say it's approximately 10 feet thick. So we are moving up to where now our target zone is roughly 50 to slightly above 50 feet off the top -- excuse me, off the bottom. Now in a 100- to 150-foot interval, we are moving up a little bit. So there is at least some fairly modest concern about full stimulation. However, we think if the lateral is roughly 50 feet off the bottom, we don't see any reason that the entire TMS should not be affected to stimulate it. But we certainly want to watch the Ash, in particular, and watch that well's performance. And all things being equal, we'd rather be down in the bottom 20 feet. So that slide to Crosby approach of getting through it and getting it behind pipe is also a very viable option. I'd say that if we have no ongoing issues or concerns relative to frac stimulation, effective frac performance, et cetera, then landing above it would be the ideal remedy.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division
Just trying to get some color on when you think this Denkmann well is going to be repaired and when that can go on in production.

Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Yes, I think -- Leo, this is Rob. I think in my remarks, I said 3 weeks. We'll set a CapEx budget early December with board approval, and hopefully, we'll be in a position to discuss the Denkmann. It's just a matter of how long the patch takes, then drill out the plugs, then run tubing. And we typically see peak rate after about a week of flowback. So it's just dependent on that. But we've said just a matter of a few weeks is what we would expect to have peak rate established.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division
Okay. And I guess any color on how that Joe Jackson well looking thus far?

Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
No. That's EnCana's operated well. They have the right to announce that and discuss that. And frankly, it's just started. So I don't even think, even if they wanted to announce, we're just not there yet. So hopefully, we'll be able to give an update on that as well when we announce the Denkmann well.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division
Okay. And in terms of the decision to do a JV, the Pearsall, the TMS and you also mentioned additional asset sales, is it safe to assume that if you were to do a significant JV, the Pearsall or TMS, that maybe that would take asset sales off the table. Is that going to be kind of an either/or type situation there?

Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
We'd like to see and get some capital of $100 million coming in the door possible. We just have to see what the optimum divestiture JV might be. We can always sell the Pearsall if we have the right valuation also. But we're intrigued by the early well results and obviously, that would give us another leg and stool on development, which is why we're playing that. But I think Beckville/Minden is the obvious noncore asset sale if you wanted to target that, doing about $15 million today. So that's probably in the range of $100 million if you wanted to sell that. But it all depends on commodity prices. That field is worth a lot more as gas prices improve, and that's why we'd like to get into early 2013 before we decide what we want to do on that.

Michael S. Scialla
 - Stifel, Nicolaus & Co., Inc., Research Division
Gil, you said you're not ready really to project any EURs for the TMS yet. But I think you guys have said in the past that if you could get the well cost in that $12 million to $13 million range, you kind of need a minimum of 350,000 boe to reach a hurdle rate. And I know you've seen some pretty steep initial declines here. But Rob, you mentioned some of the longer-term rates you're seeing out of Anderson and some of the other wells. I'm just wondering, have you seen enough yet to feel like you can get above that minimum threshold? Or is it still too early to say?

Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Mike, this is Gil. I think you're right on point. I think we would agree that's kind of the minimum number somewhere in the 300,000 and 350,000 barrel range. And we've said many times now that we're very, very encouraged, and even the first grassroots well was only a 15-stage frac. We think still early. 11 months doesn't completely make a tight curve, but we certainly feel like that well is going to land above that minimum threshold. And certainly, the 2 longer laterals are going to be significantly above that based on early-time performance.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division
Okay. And then what's the next well in the TMS after the Crosby? What's the timing on that? And have you decided yet how you'll -- you said you're trying these different alternatives. Have you decided yet how to drill that one? Or do you want to wait and see how the Ash well performs before you make a decision there?

Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Yes, that's a great question, Mike. I think ideally, we'd like to see how the Ash well performs. We're going to continue our dialogue with our partner EnCana out there between now and the time that, that well is spud. I think in terms of getting through it and casing it off, all we're really talking about is moving the base of the intermediate casing stream from the very top of the TMS, which we have to set at that point anyway, down about 50 to 100 feet. So we're really not talking about any incremental cost. So I think we view that as a pretty good insurance policy, and we have made a final determination internally. But I would say given that the Crosby goes as we expected it will, that would probably be the way we'd lean right now until we can see a little bit lengthier production performance from the Ash well.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division
So in terms of drilling that next one after the Crosby, you may not need to wait until you see results of the Ash. Is that fair?

Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Yes, I think that's fair.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division
Okay. And then anything that you saw on the core of the Crosby that leave you to believe the western side of your acreage is any different than what you've seen over the east?

Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
No. We always see nuances of geologic differences from one place to the next. But we pretty much saw on quick digital inspection, this is just last week, exactly what we were expecting to see. We were able to see very, very clearly and identified this 10-foot, very highly naturally fractured interval, which is clearly the culprit in the well bore stability issues in our minds. And we feel pretty good about it. So we'll see. We'll get the well down at Crosby [ph]. We're moving towards getting the lateral drilled, and we'll be moving towards completion soon thereafter.

Dan McSpirit - BMO Capital Markets U.S.
On the TMS, can you review the royalty burden and the severance tax regime?

Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Yes, Dan. 20% average royalty burden across our acreage. It does vary unit to unit, but that's a good blend to use. We're looking at really no severance tax in the State of Louisiana that have the horizontal severance tax abatement for a couple of years. So obviously, a big benefit there in Louisiana. And then Mississippi, very similar to the Eagle Ford. I believe it's a little over 6% severance tax on oil. So certainly, the TMS has 20% to 25% advantage right now, and the fact of LLS pricing being the breadth of TI spread is obviously very large, $20 or so, and then about 5% less royalty burden. So we're playing with the ability to able to spend a little bit more money as long as we see a similar decline curve to the Eagle Ford wells, and certainly feel encouraged early on that we have at least that on the decline curves.

Dan McSpirit - BMO Capital Markets U.S.
Okay. And then at the top of the call, you spoke about the Anderson 17H well where you have 7% working interest, I believe. And you gave a rate in over a period of time. Can you say that again? I missed it.

Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Yes, this is Gil. What I gave, Dan, was just a snapshot. I think we'll let EnCana disclose in terms of overall performance. But the well has been on a little over 5 months, and it's producing a little over 300 barrels a day.

Dan McSpirit - BMO Capital Markets U.S.
300 barrels a day, okay.

Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Of oil.

Dan McSpirit - BMO Capital Markets U.S.
Right. Got it. Got it. And let's see here. On the $12 million to $13 million drilling complete cost, does that assume a 4,000-foot lateral length? And is a longer lateral length possible considering the depth and pressure involved?

Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee and Member of Hedging Committee
Yes, actually the $13 million assumes about a 7,500-foot lateral in approximately 25 stages.

Steven Karpel
 - Crédit Suisse AG, Research Division
So if you look at on a total liquidity basis, what do you -- how do you think about what you need? And obviously, the South Henderson sale, just to take your comments at the beginning of the call, fills the 2012 gap. What do you need to do to fill 2013 and -- or maybe just fill 2013 by cutting back CapEx? And how much can you cut back?

Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Well, we can cut back quite a bit. We stagger our rig contracts so that we can release them if needed. One of the 2 Eagle Ford rigs right now is on a short-term basis. That would be easy to release. The TMS rig is just basically kind of well-to-well with 30-day notice. So we're in good shape there as well. So you're actually right. The true defensive stance would be let's just cut CapEx. We have plenty of time in the Eagle Ford. We hold all that acreage. We're still within primary term on a good bit of that. And then the TMS, we have anywhere from 18 months to 5 years of term on those leases. And then after that, we have continuous drilling provisions still for middle [ph] leases. So plenty of flexibility on cutting CapEx. I think that the reality is as we've stated by the end of the first quarter, we and the rest of the industry will have 20 to 25 wells drilled in the TMS. If you look back at the Haynesville, the Bakken, the Eagle Ford, the Utica as the great, recent example, it takes about that many wells to not only prove up what the production and EUR estimates look like, but to get your well cost down. And at that point, we think we'll have the economics proven. And that gives us a better opportunity to bring in a partner at a better valuation if we choose to go that route. And there's quite a bit of interest already in that process. We just -- or in that possibility. We just haven't started the process to bring in a partner yet. We do expect to bring in fresh capital. It's not going to be stock -- selling stock at anything close to this, and it's likely not going to be that at any price. It's likely going to be either JV or selling of a noncore property.

Pearce W. Hammond
 - Simmons & Company International, Research Division
Great color. And then switching to the TMS, what are your thoughts on quality and availability of services in the play right now?

Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Well, we use Halliburton to frac our wells over there as we do in the Eagle Ford; obviously, do a great job. We've used other operators in the past frac-ing our wells who have done an equally good job or certainly, very good jobs as well. So we feel like we have enough capacity on the pressure pumping side that's in close proximity to get reasonable frac cost. And in fact, we've already seen a reduction from the first wells frac-ed in the area to our current frac cost per stage. Feel like that's in good shape. The rig market is fine. In fact, our rig cost of late had been down probably 20% from where they were at one point. So that part has been good. It's all the other goods and services that are having to drive in from other areas, in particular North Louisiana for example, that are still having to cover for their cost to move in and move out. I think once you prove the play, that's where you start to see vast improvement in all the other goods and services. And we're pretty comfortable or certainly confident that over time, as Gil stated, we'll get these well costs to $10 million. And when you combine that with a decline curve and the economics associated with those wells that are, we think -- certainly, the decline curves as good as what we've seen in the Eagle Ford, along with the added benefits of better pricing from LLS and better royalty burdens, we think the economics are going to prove out. We're just early in the game. We just need to get a little bit further down the road before we put that stamp on it.

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