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Goodrich Petroleum (NYSE:GDP)

Q1 2013 Earnings Call

May 07, 2013 11:00 am ET

Executives

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

Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director

Jan L. Schott - Chief Financial Officer and Senior Vice President

Analysts

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Michael Kelly - Global Hunter Securities, LLC, Research Division

John Freeman - Raymond James & Associates, Inc., Research Division

Pearce W. Hammond - Simmons & Company International, Research Division

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Dan McSpirit - BMO Capital Markets U.S.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

David Snow

Chad Mabry

Operator

Good day, ladies and gentlemen, and welcome to the First Quarter 2013 Goodrich Petroleum Corporation Earnings Conference Call. My name is Dave, I'll be your operator today. [Operator Instructions] As a reminder, the call is being recorded for replay purposes.

I'd now like to turn the call over to your host, Mr. Gil Goodrich, Vice Chairman and Chief Executive Officer. Please proceed, sir.

Walter G. Goodrich

Thank you, Dave. Good morning, everyone, and welcome to our first quarter 2013 earnings call. On the call with us this morning from the company is Pat Malloy, our Company's Chairman; Robert Turnham, President and Chief Operating Officer; Mark Ferchau, Executive Vice President, Engineering and Operations; and Jan Schott, Senior Vice President and Chief Financial Officer.

As is our standard practice, we'd like to remind everyone that comments we may make and answers we may give to questions during this teleconference call may be considered forward-looking statements, which includes risks and uncertainties, and we have detailed those for you in our SEC filings.

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. Rob and Jan will review these items with you and their impact in greater detail in just a moment.

Our balance sheet is in good and improving condition. Subsequent to the end of the first quarter, we initiated and successfully raised $110 million in gross cash proceeds through the issuance of a new perpetual non-convertible preferred stock. The issue of the preferred stock, which is non-dilutive to our common shareholders and callable only by the company, allowed us to pay down on our senior revolver, boost our liquidity and significantly enhance our financial flexibility going forward.

In addition, our senior bank group has increased the borrowing base on our senior credit facility to $225 million, which added to our current liquidity, pro forma to year end -- excuse me, to quarter end of approximately $190 million. Also subsequent to the end of the quarter, we added to our oil hedged position by adding 2,000 barrels of oil per day for the calendar year 2014, priced against WTI at approximately $92 per barrel.

In addition, we initiated the first portion of our natural gas hedging strategy by layering in an initial 10 million cubic feet of gas per day at NYMEX price of $4.18 per MMBtu for the period of October 2013 through December of 2014. We continue to watch both the crude oil and natural gas markets carefully, with plans to add to our position opportunistically over time to build an additional cash flow protection.

In the Eagle Ford Shale, our drilling team continues to turn in record performance with spud to total depth averaging approximately 10 days per well, a reduction of approximately 57% compared to our initial wells drilled in the play. The improved drill time performance is allowing us to not only increase the number of wells drilled per rig, but also to reduce overall completed well costs, and build on our inventory of wells drilled and ready for completion.

Our wells in the Eagle Ford Trend continue to perform very well. And after adjusting for offset well completions, shut-in time and short-term frac water interference, our wells continued to perform on curve with a normalized internal EUR projection of approximately 425,000 BOE.

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 split 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 Canada. 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.

And with that, I'll turn it over to Rob Turnham.

Robert C. Turnham

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 mid 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.

Focusing on results for the quarter, production was 6 Bcf equivalent, with average production of 3,525 barrels of oil and 46 million cubic feet of gas per day. Oil and gas volumes were negatively impacted by approximately 300 barrels of oil per day and 4 million cubic feet of gas per day due to shut-ins from offset frac operations in both the Eagle Ford and Haynesville areas. We conducted drilling operations in the quarter on gross -- 8 gross, 3.6 net wells, added 8 gross, 4 net wells to production, with 18 gross, 10 net wells waiting on completion at quarter end.

We currently have 1 rig running in the Eagle Ford and expect that to continue throughout 2013 with our wells currently averaging 10 days spud to total depth for a 6,000-foot lateral, 13 days to rig release at an estimated 20 days spud to spud. The increased cycle times have caused our inventory wells drilled but uncompleted to grow to 9 gross 6 net Eagle Ford wells at quarter end. Due to timing of pad-drilled wells, we only completed 3 gross, 2 net Eagle Ford wells in the quarter, which is well below the 24 gross, 16 net wells we expect to add to production for the year. We currently have 18 gross, 12 net Eagle Ford wells scheduled for completion over the next 2 quarters.

On our gas assets, we have commenced completion operations with Chesapeake on the deferred Haynesville wells in North Louisiana, with completion spread out primarily over the second and third quarters. In the Angelina River Trend, we completed ACLCO #1 at an early restricted choke flow rate of 7 million cubic feet per day and we plan to continue with our restricted choke program in the well as it cleans out.

In closing, our natural gas assets are intact for future development. The Eagle Ford continues to provide steady oil volumes and attractive rates of return. And we remain very excited and optimistic about the economic viability which [ph] in us and the tremendous upside the play it provides for the company.

With that, I would like to it over to Jan Schott to walk you throughout the financials.

Jan L. Schott

Thank you, Rob. Good morning, everyone. I will cover a few items on the financial side.

Revenue for the quarter totaled $47.1 million, an increase of $1.8 million or 4% over revenue for the comparable period last year, and $1.1 million or 3% below revenue for the fourth quarter 2012.

Our first quarter average realized prices, excluding the impact of realized gains on derivatives, were $107.02 per barrel for oil and $3.40 per Mcf for natural gas.

As Gil previously discussed, in early April, we layered on an additional 1,000 barrels of oil per day swapped for Cal 14 at $92.95 per barrel. Yesterday, we layered on an additional 1,000 barrels of oil per day Slough for Cal 14 at a blended price of $91 per barrel.

In early April, we also added a natural gas swap on 10,000 MMBtu per day for October 2013 through December 2014 at $4.18 per MMBtu.

Our plan is to continue to layer on additional oil derivatives as we increase oil production during 2013. We also continued to watch natural gas for additional opportunities to hedge portions of our 2013 and 2014 natural gas production. Please see our website later today for an updated slide on our current derivative position.

Also, we are confirming previous 2013 production guidance. We estimate oil volumes to grow by 40% to 60% in 2013 versus 2012, with natural gas volumes to grow by 10% to 15% from fourth quarter 2012 to fourth quarter 2013, but down year-over-year by about 10%. Total production on an Mcfe basis is expected to be relatively flat year-over-year. We expect oil volumes to represent about 30% to 35% of total production and 65% to 70% of revenue for 2013.

Moving on to expenses. LOE per Mcfe this quarter was $7.2 million or $1.20 per Mcfe. The first quarter includes about $1.6 million or $0.27 for workovers primarily in the Eagle Ford Shale. The first quarter also included higher chemical production enhancement and compressor costs as compared to last year. Most of these costs relate to our South Texas oil property. As we have stated before, as we increase our oil production, we would expect our LOE rate per unit to gradually increase over time with oil production representing 31% of total production in the first quarter.

DD&A per Mcfe was $5.84 for the quarter compared to $5.62 last quarter and $3.68 for the prior year quarter. The higher DD&A rate compared to last year is related to more oil production from our Eagle Ford Shale, which carries a higher FMD costs per Mcfe than our lower natural gas property. We would expect this trend to continue as we increase oil production throughout 2013.

Exploration costs for the quarter of $3.3 million or $0.56 per Mcfe includes $1.4 million related to the exploration of undeveloped lease holds, which is noncash, $0.4 million of seismic and $0.2 million for dry hole costs.

G&A costs came in at $9.4 million, $1.57 per Mcfe this quarter compared to $0.90 in the prior year quarter.

The first quarter included $1.5 million for 2012 bonus paid in 2013 and the associated payroll tax. About $0.30 or 19% of the first quarter rate represents noncash stock-based compensation.

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. Following the success of the Crosby TMS well, we expect Eagle Ford Shale CapEx at the low end and TMS 2013 CapEx at the high end of CapEx ranges previously given.

At the end of the quarter, we had $145 million drawn under our senior credit facility and $4 million in cash. As Gil mentioned earlier, we issued $110 million in non-convertible preferred stock in early April, and our bank group recently increased our borrowing base to $225 million based on our year-end reserve report. We used net proceeds of $106.5 million from our preferred stock issuance to pay down drawings under our revolver, resulting in pro forma quarter-end liquidity of $190 million.

The next redetermination of our borrowing base will occur in October 2013 based on our mid-year reserve report.

We have included reconciliations on the last pages of our press release for all non-GAAP measures to the closest GAAP measure. Please refer to these reconciliations for more detail. We plan to file our first quarter 2013 10-Q with the SEC later today. Please see our 10-Q for a more detailed financial discussion.

With that, I will now turn it back to Gil for some closing comments.

Walter G. Goodrich

Thank you, Jan. We expect our recently initiated plan of completing previously drilled Haynesville Shale wells will result in a turnaround in natural gas production and see us grow net gas production in the second half of this year. And with natural gas prices now over $4 per Mcf, it should have a meaningful impact on operational performance.

As we move forward over the coming months, we will continue to look for opportunities to further strengthen our balance sheet and build upon our financial flexibility.

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.

That concludes our remarks, and we'll now turn it back over to Dave for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of line of Leo Mariani at RBC Capital Partners.

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

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 -- and 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

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

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.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay, that's helpful. I guess just in terms of costs -- I mean, obviously you guys talked about some one-off costs this quarter. Just looking at your LOE, if I were to back out kind of the $1.6 million of workovers, I'm seeing about $0.94 per Mcfe in the first quarter. And then you guys came in around $0.71 in the fourth quarter of '12, so I guess it was still up a fair bit. Just trying to get a sense of -- I think you commented that costs may continue to creep up. Should we expect it to be around that $0.94 per mcfe or higher kind of the rest of the year on LOE?

Robert C. Turnham

Well, I'll tell you, Leo. What affected this quarter was lower gas volumes, shutting in the Haynesville wells, which carry a 20%, 25% per Mcfe LOE. So that 4 million a day that were shut in certainly took some of the per unit costs higher. And as Gil said, we're going to be layering in these gas wells, for example, the ACLCO's LOE, that well could be less than $0.10 an Mcfe. So I think, going forward, even though we're adding oil volumes, which carried a higher LOE per unit, as we layer in these gas wells, we think you're going to see a reduction for the remainder of the year once the gas wells come online. So I'm happy to kind of get with you offline, but we would expect that trend not to continue to rise. I would say probably flat to slightly down in the second quarter, but certainly, as these gas wells come online, we're expecting it to be lower than what you saw in the first quarter.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. So I guess that you guys are anticipating that your big gains in gas production are really going to come in the third quarter? Should I infer that from your statement there?

Robert C. Turnham

Well, the ACLCO was completed after the end of the first quarter, so that one's clearly going to be in the second quarter, and then they're going to -- Chesapeake's going to gradually bring these wells on that have already been frac-ed and then they will be staggered throughout the second and third quarter primarily. So I would say, certainly, we are expecting, as Gil said, to see gas volumes growing, beginning in the second quarter and accelerating throughout the rest of the year.

Operator

The next question comes from the line of Mike Kelly at Global Hunter Securities.

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

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

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.

Operator

And your next question comes from the line of John Freeman at Raymond James.

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

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

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.

Operator

Your next question comes from the line of Pearce Hammond at Simmons and Co.

Pearce W. Hammond - Simmons & Company International, Research Division

With the improvement in gas prices, would you consider monetizing your Louisiana Haynesville assets to help further your development in the TMS?

Walter G. Goodrich

No. Not yet, Pearce. We like our gas sets quite a bit. We are pretty long-term thinkers around here and long-term focused. And we are blessed with a largely held bi-production footprint in the -- excuse me, in the Haynesville. And we are very happy just to continue to watch the gas market carefully and be very careful with our capital allocations between the different assets that we do have.

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

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.

Operator

The next question comes from the line of Joseph Allman at JPMorgan.

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

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

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

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 line 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

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.

Operator

Your next question is from Ron Mills with Johnson Rice.

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

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

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.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay. And -- good. And then in the Eagle Ford, primarily, and maybe to a letter extent, the Haynesville, the production impacts from shut-ins as you do pad drilling or complete offset set wells, what's different about, if anything, second quarter through fourth quarter completions in terms of locations relative amount of development around your upcoming completions? Are -- is that going to be a similar side impact going forward or was the first quarter, particularly in Eagle Ford, more impacted by being more focused in more developed areas?

Walter G. Goodrich

Ron, this is Gil, I'll take that one. It really is about the geographic location of the pad that we plan to move onto here later in the second quarter and into the third quarter. And we have planned that we'll move the rig away from those more densely drilled areas, and therefore, we think you'll see a mitigation of the impact as we get into the second half of the second quarter, and certainly, into the third quarter. So we won't rule out any impact as we go forward, particularly in the third quarter, but it certainly is going to be substantially less by our estimates than what we've seen here in the first quarter and really over the last couple of quarters.

Operator

Your next question is Mike Scialla at Stifel.

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

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

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.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay, good. And then switching over to the Haynesville. Your ACLCO well, how does that compare to other wells in the area? And maybe based on pressures there -- and I know it's real -- fund at a real restricted rate, but maybe based on the pressure and net pay you saw?

Robert C. Turnham

Yes. It's still too early, Mike. This is Rob. I mean, we've reported -- obviously, the 7 million a day, with 7,775 pounds of pressure, we are -- gosh, real early on that flowback. We've thought about not including it just yet until we see where it winds up. There is a real chance that even on the same choke that we could see higher rates. But it's in an area that -- it had very good wells, including, I think, just on the south side of us were the EOG Sarge wells, and has been really outstanding. So I would say, no reason to think that this well is not going to perform well at this point in time. It's just unfortunately, we just barely have it producing. I think it's been on for a very short period of time. So we'll give an update on that in our management presentation as we continue to see how the well does. But we're pleased with what we see so far. It's just way too early. We're just going to be gradual as to whether we open the choke or not, and when we open the choke.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay, understand. And then last one from me. On your guidance, you said production is going to be pretty flat year-over-year and you're sticking with your fourth quarter -- over fourth quarter rates. I know you didn't give quarterly guidance, but just so I understand, directionally, is it going to be kind of a linear increase from here to fourth quarter? Or it looks to me like there might be kind of a bump up in the second and third and then more of a leveling out in the fourth, am I thinking about that correctly, directionally?

Robert C. Turnham

I think directionally, you are, Mike, mainly just because of the Chesapeake completions being in the second and third quarter. So you're going to likely see a peak, I would say, about the end of the third quarter and then flattish in the fourth quarter sequentially. But I think you are thinking of it right. Should -- since the growth beginning, second quarter and then probably a bigger rate of growth in the third as all those wells come online.

Operator

Your next question comes from Dan McSpirit at BMO Capital Markets.

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

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

Yes. Dan, this is Gil. You're right, it is little early. And obviously, it's pretty dependent [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

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

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.

Operator

Your next question comes from the line of Richard Tullis at Capital One Southcoast.

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

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

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.

Operator

Your next question comes from the line of Steven Karpel at Credit Suisse.

Unknown Analyst

This is actually Brian Chevry [ph] on behalf of Steven. Just a quick question, how do you guys look at the converts? And I guess, those are portable [ph] next year, how do you kind of look at that, and any plans at this point on how you may address those?

Walter G. Goodrich

Yes, this is Gil Goodrich. We had said before that we have a number of different ways we can go about doing a redemption of those notes. We could continue to increase capital through a tack on to the existing preferreds that we put out, that's an alternative. We could sell a portion or all of our East Texas Cotton Valley assets. There's a pretty ready market for that should we decide to do that in the second half this year. And use those funds to redeem some portion or perhaps all of the converts. And also could discuss either taking them out with a new convert or more likely some sort of an amendment extend on those that would move the put call date back a couple of years. So all of those things are in the mix and we've talked about addressing those before the end of this year.

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

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

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.

Operator

Now, you have another question from Mike Kelly at Global Hunter Securities.

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

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.

Operator

And now, we have a question from David Snow at Energy Equities Inc.

David Snow

What was the well -- the Crosby well cost?

Walter G. Goodrich

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

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

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

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

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

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

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

We understand that.

Operator

Your next question is from Chad Mabry, The Energy Report.

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 at this point in that kind of that Emmet, Wilkinson County area?

Walter G. Goodrich

Yes. I think, if you take our acreage position that's in Emmet 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

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 Emmet Wilkinson County area for the near term.

Operator

Thank you. There are no further questions for you gentlemen. So I'd now like to turn the call back to back to Mr. Gil Goodrich for closing remarks.

Walter G. Goodrich

Thank you, Dave. Thank you, everyone, for your participation. We look forward to visiting with you again in a few months and reporting 2Q. Thank you.

Operator

Thank you, everybody. Today's conference is now concluded. You may now disconnect. Have a very good day.

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