Goodrich Petroleum Management Discusses Q2 2013 Results - Earnings Call Transcript

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Goodrich Petroleum (NYSEMKT:GDP) Q2 2013 Earnings Call August 7, 2013 11:00 AM ET

Executives

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

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

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

Analysts

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

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

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

Michael Kelly - Global Hunter Securities, LLC, Research Division

Brian M. Corales - Howard Weil Incorporated, Research Division

Stephen F. Berman - Canaccord Genuity, Research Division

Subash Chandra - Jefferies LLC, Research Division

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

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

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

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Louis Baltimore - Macquarie Research

Operator

Good day, ladies and gentlemen, and welcome to the Second Quarter 2013 Goodrich Petroleum Corporation Earnings Conference Call. My name is Shaquannah, and I will be your coordinator for today. [Operator Instructions] I would now like to turn the presentation over to your host for today's call, Mr. Gil Goodrich, Vice Chairman and Chief Executive Officer. Please proceed, sir.

Walter G. Goodrich

Thank you, Shaquannah. Good morning, everyone, and welcome to our second quarter 2013 earnings call. I'll begin with the introduction of the management team here with me this morning, beginning with Pat Malloy, the Chairman of the Board; 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.

I would like to remind you that we will make statements and answer questions during this teleconference call, which may be forward-looking statements and involve risks and uncertainties, and we have detailed those for you in our SEC filings.

Rob and Jan will provide more color on the second quarter in just a few minutes. But this morning, I will confine my comments to the Tuscaloosa Marine Shale play.

As we announced on July 22, we have entered into an agreement to purchase 7 producing horizontal wells in the Tuscaloosa Marine Shale play and a 66.6% -- 66.7% working interest and approximately 277,000 gross acres or approximately 185,000 net acres for $26.7 million. Our due diligence is progressing well, and we expect to close this transaction in the next couple of weeks. While we have not previously announced it, we can now confirm the seller is Devon Energy, and we've been working closely with them to consummate this transaction.

Also, as many of you are aware, Devon had previously entered into a large joint venture, covering 5 emerging crude oil and liquids plays in the United States with Sinopec, and Sinopec has elected to retain their 1/3 working interest in the properties and jointly develop this acreage with us. We welcome them as a partner, and look forward to working with them on our joint development activities, which will begin in the fourth quarter this year.

We view this acquisition as very meaningful for our shareholders for a number of strategic reasons. First, our footprint in the play will more than double from 135,000 net acres to approximately 320,000 net acres. Second, the additional acreage materially expands the range, diversity and balance of our overall position in the TMS. Third, the combination of the present value of the proved developed producing reserves associated with the 7 producing wells, and upon closing, the corresponding $18 million increase in our borrowing base under our senior credit facility allows us to complete this acquisition with negligible impact to our current liquidity. Finally, the transaction accelerates our transition from a company whose reserves and inventory were dominated by natural gas towards a very balanced portfolio, with tremendous opportunities for crude oil production and reserve growth.

In summary, we view it as a near ideal acquisition with very limited well-defined down risk and tremendous, almost unlimited upside potential for our shareholders.

We are very pleased with the positive momentum created by the recent TMS wells, including our company operated Smith 59 -- excuse me, 5-29H-1, and the EnCana-operated 17H-2 well we announced yesterday, which set a new 24-hour initial production record for the TMS of over 1,500 barrels of oil equivalent per day. The EnCana-operated Anderson 17H-3 is in very early stages of flowback but is trending in the right direction, and we expect another solid result from this well, which will be reported once a peak rate has been reached.

We are currently drilling the company-operated CMR/Foster Creek 20-7H-1 well, which is drilling in the lateral section and nearing total depth. We expect to complete this well in early September.

Recent well results have continued to enhance our knowledge of the play, both in terms of improved drilling procedures, including the lateral landing target, which has led to 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. While we do not profess to have all the answers, we do believe the right mix of fluid volumes, profit amounts and play stabilization additives are critical to achieving successful results in a TMS.

The positive incremental data points across the play has given us further encouragement to take another step forward into the development of the play and our acreage. As such, we are now planning to reallocate approximately $15 million of capital expenditures in the fourth quarter of this year from the Eagle Ford Shale play to the TMS. We are actively working on our development plans for the newly acquired acreage, and the incremental allocation of capital will allow us to begin development of this newly acquired acreage during the fourth quarter of this year. With continued success, we expect further acceleration of our TMS development activities in 2014.

The acquisition obviously provides us with an extremely large footprint in the core of the TMS. And while we cannot and will not, at this point, rule out any of the acquired acreage from being perspective, we will be very judicious in our process to determine which acreage to develop first, which acreage to extend the fixed extension payments and which acreage should potentially be released. The vast majority of the newly acquired acreage, as well as our existing acreage is covered by lease extension options, which provide for the leases to be extended for 2 or 3 additional years at a very low per acre. In addition, a portion of the acreage contains continuous drilling provisions would provide for the leases to be held or extended beyond the primary term through periodic development drilling.

In summary, the exact amount and location of the acreage we expect to retain, potentially all of what we acquire, will be based on a number of factors, including the timing and amount of lease extension payments, possible changes in geology across the play, potential variations in results of future development activity, our ability to access incremental capital over the next 3 to 5 years and our ultimate rate of development of the play.

While impossible today to predict the exact timing, size and structure of a potential TMS-related financing, we remain optimistic our menu of options will continue to expand with further success and development of the acreage.

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

Robert C. Turnham

Thanks, Gil. We are still early days in the TMS, but we can't help but be optimistic about the play at this point, as we see continuing improvement and repeatability of well results. And expanding core position with the spread of successful wells over our large areas, such as our Smith well, which is approximately 36 miles away from the Crosby. And costs trending down, thereby establishing very attractive economics.

The Smith well, which is approximately 5,400 feet of usable lateral with 20 successful frac stages, has averaged approximately 1,000 BOE per day of our 12/64-inch choke over the recent 8 days after reporting a 24-hour average rate of 1,045 BOE per day. The EnCana-operated Anderson 17H-2, which as Gil stated earlier, had the record IP to date of 1,540 BOE per day, had a similar frac design to the Crosby and a similar lateral links to the Smith well. Both of these wells had 95% to 96% oil cuts. The Anderson 17H-3 is in early flowback, and we expect that result to be good as well.

There is no denying that the oil is in place and recoverable in the TMS, as our Crosby well has produced in excess of 100,000 barrels equivalent in 5 months, with an approximate 92% oil cut, and is still producing approximately 375 BOE per day currently, as we near the end of the 6 months of normalized production.

If you spot 375 BOE per day on our 800,000-barrel equivalent type curve at 6 months, you will see the decline has been flatter than expected, and we continue to trend above the curve. If you plot 100,000 BOE on our accumulative production curve at 5 months, you will see that Crosby is well above any other well in the fields and reached 100,000 BOE in half the time as compared to the better Bakken wells.

We are currently drilling a lateral on our CMR/Foster Creek well in Wilkinson County, Mississippi, in which we own a '99% working interest, with plans to move to our hub location in Amite County Mississippi next, where we own a 97% working interest. Our current plans are to spud 3 additional operating wells by the end of the year.

We are seeing well costs come down in the TMS, as our Smith well was drilled and completed for approximately $13 million. We continue to believe we can drive our costs down over time to the $10 million range through better drilling efficiencies, pad drilling, zipper fracs and a more competitive service company environment.

I want to remind you that even at current well costs, the economics are compelling in the play and very similar, if not superior, to what we see in the Eagle Ford. Our 800,000 BOE curve at $90 WTI produces a 56% internal rate of return, with 15% to 20% incremental IRR for every million dollars of savings or $10 movement in oil prices.

The economics are driven off of very attractive production rates, as well as certain inherent advantages of our other oil plays, such as our production stream is 90% to 96% black sweet oil, priced at approximately $2 off of LLS, and we continue to receive north of $100 per barrel; our gas has a high BTU content, with approximately 80 to 100 barrels of NGLs per million cubic feet produced; we have 24 to 30 months of severance tax relief in both states of Louisiana and Mississippi; our royalty burdens averaged approximately 19% across our combined acreage block versus much higher in other plays; and we are dealing with cooperative landowners and efficient state agencies for regulatory purposes.

Focusing on results for the quarter. Production increased by 10% sequentially to 6.7 billion cubic feet equivalent, or an average of 73.2 Mcf equivalent, million cubic feet per day, versus 8.3 Bcf equivalent or an average of 91 million cubic feet equivalent per day in the prior year period. Oil production for the quarter totaled 292,000 barrels of oil on an average of 3,209 barrels per day, versus 254,000 barrels of oil or 2,791 barrels per day in the prior year period. Natural gas production for the quarter totaled 4.9 Bcf or an average of 54 million cubic feet per day. Oil production continued to be affected by frac interference in the Eagle Ford, as we drilled up most of our acreage on a portion of our block with pad-drilled wells.

To give a little more color on the impact of frac interference, when we initially drilled the wells in the Eagle Ford, we spread those wells out to the de-risk the acreage. As we've come back in and down space to 80-acre offsets between the previously drilled wells, we've seen the frac fluid distributed over large areas, affecting wells in the area of stimulation. Once the fracs are completed and frac fluid is produced, then we move off of an area. The wells come back on line and return to their previous rate, but it takes some time.

We are seeing the frac interference subside now, and we'll continue to do so gradually as we move to different areas with less interference expected. And as shown in the press release, we are currently producing approximately 4,300 to 4,500 barrels of oil per day.

For the quarter, we conducted drilling operations on 9 gross, 5.6 net wells; of which 7 gross, 4.7 net wells were in the Eagle Ford; and 2 gross, 1 net were in the Tuscaloosa Marine Shale trend. A total of 17 gross, 8.9 wells were added to production during the quarter; of which 9 gross, 6 net were in the Eagle Ford. About 3 gross, 2 net wells were added late in June in the Eagle Ford, and therefore, had very little production for the quarter. As of June 30, the company had 11 gross, 5 point -- net wells waiting on completion; with 3 gross, 1.5 net in the Haynesville Shale trend; and 5 gross, 3.3 net in the Eagle Ford Shale trend.

We currently have 1 rig running in the Eagle Ford and expect that to continue to the third quarter of 2013, with plans to pick a rig back up in the first quarter of 2014. Well costs in the Eagle Ford continue to fall for the quarter, with well cost averaging below $7 million per well for 6,000-foot laterals.

Finally, to account for our TMS acquisition of $27 million, our capital expenditure budget for 2013 has moved from $200 million to $230 million, with drilling CapEx remaining the same as before, with the exception of the $15 million reallocated from the Eagle Ford to the TMS.

With that, I would like to turn it over to Jan Schott, who'll walk you through 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 $48.5 million, an increase of $7.1 million or 17% over revenue for the comparable period last year, and an increase of $1.4 million or 3% over the first quarter of 2013. Our second quarter average realized prices, excluding the impact of realized gains on derivatives, were $101.62 per barrel for oil and $3.75 per Mcf for natural gas.

For the balance of 2013, we have 3,500 barrels of oil per day hedged at a blended price of $94.50. During the quarter, we added to our hedge position for 2014. We now have 50,000 MMBtu per day of natural gas hedged for 2014 at $5 and 3,500 barrels of oil per day hedged for 2014 at $95.32. This includes counterparty options to swap. Please see our website for more details on the current derivative position for the company.

We are updating full year 2013 production guidance to address the experienced frac interference in the Eagle Ford Shale and delays due to the reallocation of capital from the Eagle Ford Shale to the TMS later this year, as previously mentioned by Gil and Rob. We estimate oil volumes to grow by 30% to 40% in 2013 versus 2012. Total production on an Mcfe basis is expected to decrease by 5% to 10% year-over-year. We expect oil volumes to represent about 30% of total production and 65% to 70% of revenue for 2013.

Moving on to expenses. LOE per Mcfe this quarter was $5.9 million or $0.88 per Mcfe, down $0.8 million from prior year quarter and down $1.3 million from last quarter. The second quarter includes about $1.1 million or $0.17 for workovers, primarily in the Eagle Ford Shale.

DD&A per Mcfe was $5.18 for the quarter compared to $5.84 last quarter and $4.17 for the prior year quarter. The higher DD&A rates compared to last year is related to more oil production from our Eagle Ford Shale, which carries a higher F&D costs per Mcfe than our natural gas property. We would expect this trend to continue as we increase oil production in 2013. We will adjust our DD&A rates in the third quarter upon the receipt of our midyear reserve report.

Exploration costs for the quarter, at $9.5 million or $1.43 per Mcfe, includes $7.5 million related to the exploration of undeveloped leasehold, which is noncash. As part of our capital allocation process, we elected not to renew certain expiring leases located in non-core Eagle Ford Shale Trend acreage. For most of this acreage, the Eagle Ford Shale was not the primary target. This acreage was mostly located in the northern section of our Eagle Ford Shale position. Exploration expense for the quarter also includes $0.6 million for seismic expense.

G&A costs came in at $7.6 million or $1.15 per Mcfe this quarter, compared to $0.81 in the prior year quarter and $1.57 per Mcfe last quarter. About $0.26 or 22% of the second quarter rate represents noncash stock-based compensation. We are continuing to project a 0 tax rate for the full year of 2013.

At the end of the quarter, we had $2.7 million in cash and $75 million drawn under our senior credit facility, which has a $225 million borrowing base, for a total of $153 million of liquidity. Upon closing the TMS acquisition, our borrowing base will increase $18 million to $243 million. As Gil mentioned earlier, we expect the TMS acquisition to close by August 22. The next redetermination of our borrowing base will occur in October 2013, based on our midyear reserve report.

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

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

Walter G. Goodrich

Thank you, Jan. Clearly, our near-term focus is, as we think it should be on the TMS, as recent results in our pending acquisition provide a tremendous catalyst for production reserve and NAV growth. Given the current state of the play, we fully expect further acceleration of TMS activity as we move forward and into 2014. However, at the same time, we will continue with the development of our Eagle Ford Shale assets, albeit at a slower pace.

In addition, the natural gas hedges we have added during the second quarter at $5.06 per Mcfe for calendar year 2014 provide us with approximately 50% of our current natural gas production covered by fixed price hedges for next year at a blended average price of $4.76 per Mcfe. This attractive hedge position allows us to comfortably allocate approximately 10% to 15% of our anticipated 2014 budget to further the development of our Haynesville Shale assets.

And with that, I will turn it back over to Shaquannah for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Neal Dingmann, representing SunTrust.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Gil, for you, or Rob, just wondering on the TMS these days, what about service costs and all, just how they're sort of trending? And are you seeing any difference -- and you're starting to see more activity coming to the play for the services?

Robert C. Turnham

Yes, Neal, this is Rob. We are seeing a little bit better competition on the bidding process. We would expect that to continue just like any other play. The more success, the more comfort -- that not just investors have and the company has, but the service companies have, the more they'll move in extra capacity into the market. And we're starting to see that, and we're starting to feel some incoming calls on equipment moving into the market. So we'll continue to get commentary on that as we go forward, and certainly that's a part of us driving well costs down, is just a more competitive service environment.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

And then just one, Rob, a follow-up to that, as far as TMS, just other operator activity, if you're starting to, maybe besides EnCana, seeing any increase in activity? And will you continue to sort of share data with EnCana and others in the area?

Robert C. Turnham

Well, we'll -- we have a very good working relationship with EnCana. Our footprints in Mississippi are very similar, so we expect that relationship to continue and the exchange of information to continue. Certainly, other operators to the west of us that we continue to monitor. We are also hearing about some acreage packages getting a good bit more interest than, maybe, they previously had. I think everyone's kind of coming to the conclusion at a similar time that the play is looking better and better. So we would expect to see the activity level, not just for us that are currently in the play increase. And we expect a number of firms to be drilling more in 2014. But we expect to see new entrants. It wouldn't surprise us to see new entrants in the play before too long.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Okay. And then just one last one for me. Regarding the Eagle Ford frac infrastructure, is that -- did I understand that right from Rob, as far as just in that certain area, or if you could just -- maybe a little more color on your thoughts as you continue to sort of drill into the entire area? I'm just trying to get an idea of how much or what areas you think you'll have the frac interference?

Walter G. Goodrich

Sure. Neal, this is Gil. So obviously, one of our objectives was to drive costs down in the Eagle Ford. As Rob mentioned, we've been successful in doing that. However, one of the key drivers in driving those costs down has been getting on pad drilling, drilling at least 3 wells per pad, leveraging off of that, as well as zipper fracs, and we've done that in a fairly concentrated area of one large ranch down there. And as we experience as every time we go frac up a new 3 well pad, you've got numerous wells all around that pad that are getting influenced by the frac fluid. It generally takes anywhere from 2 weeks to 6 weeks for those offset wells to produce off that induced frac water, and get back on to their 3 offset frac curves, if you will. We've seen it now many, many times over many, many wells. And in each case, those wells, obviously, is a finite amount of frac fluid being induced. It's gotten right back on its curve. But it has clearly impeded us quarter-over-quarter. So a combination of us shipping capital away from the Eagle Ford temporarily and over to the TMS, as well as moving to a different part of both that one ranch, as well as another ranch, we think is going to start to allow those wells to heal and get back up on their curve. And we think that's a positive for us in terms of quarterly reported volumes going forward in the second half of this year.

Operator

Your next question comes from the line of Leo Mariani, representing RBC.

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

A couple of quick questions on the TMS. What's the current rate on the Smith well?

Robert C. Turnham

Well, we just prepared that press release, and that was a similar rate to the average rate. So we're trying to kind of maintain a more conservative choke program there and keep that curve as flat as possible. So yes, it's in the same vicinity that what we reported in the press release.

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

All right. So basically, not really seeing any declines on your restricted program on that well at this point?

Robert C. Turnham

Well, anytime you restrict it, and you could see that, that was reported on the 12/64 choke, you tend to flatten the curves. And no difference here versus what we've seen in the Haynesville or the Eagle Ford for that matter. So just focusing on chokes, for example, I think what's important to look at on the Anderson 17H-2 is just with a very slight change in choke, you can see the potential impact of volumes going forward. And so we think all of these wells are kind of in the neighborhood of each other. And the play, frankly, has needed that repeatability results at very attractive rates, and we feel like we have that with these 2 wells.

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

Okay. And obviously, on the second Anderson well from EnCana, is that something you all would expect to release literally in the next couple of weeks? Should we see that as kind of an imminent data point out there?

Robert C. Turnham

Well, we're going to continue to coordinate that with EnCana. We obviously said that we will release it and then we do plan to do that. So when and where and how, we'll have to just figure out in our conversations with EnCana also.

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

Okay. And in terms of funding, I guess, in your prepared comments, you talked about sort of a variety of different options. Is there anything you may be leaning more toward, like potentially the asset sale of the Cotton Valley you guys talked about? And then, what would you all expect to realize on your fall borrowing base? Would you expect to see a nice bump there?

Walter G. Goodrich

Yes. Leo, this is Gil. I think in my prepared remarks, I tried to lay it out as clearly and succinctly as I possibly could. Today, it's just very difficult to pinpoint exactly what we might do. We think that we're heading in the right direction. We're making good progress. We can continue on that path. More and more options open up for us. And so as we've always done in the past, we're going to find those transactions that we think best benefit our shareholders with the least amount of dilution and the maximum benefit. So I think we're comfortable working forward here for the next few months. And getting into the fourth quarter, we'll just see how things progress.

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

All right. And I guess what are you all expecting for the borrowing base this fall? Do you expect to see a bump there?

Walter G. Goodrich

We think so. Again, we hate to get out and prejudge our reservoir engineers or our bank group, but we're clearly getting a nice bump here, contemporaneously with the closing of the Devon acquisition. We think that's positive. We've certainly added some volumes here as we talk about what current rates are today. We think that's a positive. So clearly, internally, we think the bias is for an improvement in the borrowing base, but we won't try to prejudge what that might be.

Operator

Your next question comes from the line of John Freeman, representing Raymond James.

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

You all mentioned the change on the choke size on the Smith well after it had been aligned for a few days. I'm just curious, on the Crosby well, did that one stay at the 15/64 as it initially came on at over the 6 months?

Robert C. Turnham

We made gradual -- John, this is Rob. We made gradual adjustments along the way. One thing we do is let the well tell you what it needs. And, for example, when a well starts to load up, we might bump it by 1/64. So along the way it helps unloads the fluids and get -- and continue on that curve. But the last thing we want to do is open the choke pretty rapidly. We think holding back pressure on the well makes a lot of sense. It keeps the fractures open and keeps you from prematurely depleting any of those stages. So we can -- and we'll adjust the choke on the Smith over time also. I mean, that's just a plan. We monitor it daily. We subscribe and probably pay attention on a daily basis more than those. But we feel like the well will tell you what it needs to flow back on. And then we'll put the well -- we'll run tubing, obviously, within 60 days typically, and then we put it on artificial lift, maybe a little earlier, such that we maximize our production and again, efficiently produce the well.

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

And then on the Anderson well, was there anything that was done differently on that well, in terms of like maybe the amount of proppant that was used per stage relative to the Crosby or the Smith? Or were they pretty similar?

Walter G. Goodrich

John, this is Gil. They did pump slightly higher proppant amounts. Fluid volumes were pretty darn similar to what we had pumped on both the Crosby and the Smith. But they were probably 15% higher on volumes of proppant, so they were able to get it away. We think that, that make some sense and looks pretty good, and certainly you can't early on argue with the Anderson 17H-2 results. So we're looking at that really hard. I would tell you, it's -- another important ingredient in our mind is, otherwise, they pump exactly the same fluids, including play stabilization that we pump on the Crosby and the Smith. And so we, at least internally at Goodrich, think that's the right way to go.

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

And then just the last question for me. Have you all made a determination yet on the CMR/Foster Creek well, how long that lateral is going to be?

Walter G. Goodrich

No. We're drilling today -- John, we're planning to go out, call it 6,000 to 6,500 feet of lateral length. But as Rob, I think, mentioned the Anderson 17H-2 was about 5,200 feet. And that, in our mind, is pretty well, dictating that at least that is sufficient lateral length if you do everything else properly. So I think if we'd get out beyond, say, 5,000, 5,500 feet, if we start having any issues or problems or feel like we need to make a trip for whatever reason, then we certainly could call it a day at that point. But if it's going smooth, with no issues, we will plan to get out to 6,000, to 6,500 feet.

Operator

Your next question comes from the line of Mike Kelly representing Global Hunter Securities.

Michael Kelly - Global Hunter Securities, LLC, Research Division

I was hoping you guys could give some color on the current 375 BOE per day rate on the Crosby. Could you quantify the outperformance versus your high-case TMS-type curve? I guess, specifically, I'm wondering what the daily rate should be at the end of month 6, if you were sitting right at that 800,000-type curve level.

Walter G. Goodrich

Yes, Mike, give me 1 second. You caught me a little bit off guard on the management presentation in that curve. But yes, we've seen some -- we saw some commentary earlier today that, as compared to their curve, that they felt like the Crosby well was -- had a steeper decline than what they were expecting. And I would tell you that that's exactly opposite of what we would suggest. It looks to us -- if you look at month 6, our 800,000-barrel curve, it's supposed to be about 275 barrels equivalent, not 375 barrels equivalent. So if were to look at it at that percentage above the curve, I think that was just a wrong reference and perhaps that morning note was taking 5 months at 375 instead of 6 months at 375. Until we hit 6 months, and we're probably less than 1 week away, we just give monthly updates on that. So all we have is month -- through month 5. And I'll tell you what, you cannot -- and I mentioned it in my prepared remarks, if you look at cumulative production curve compared to the other wells and -- in an Eagle Ford well or a Bakken well, you can't deny that that well is not outperforming significantly above that. As I said, we had 100,000 barrels equivalent half the time that was the normal -- that really good Bakken wells do. So we're very pleased with the results. We put it on jet pump, it went on artificial lift, just like all these other wells. And frankly, we've been pleased as to how the jet pump is moving the fluids. That's something that's -- this is the first well that's been -- that we've tried to jet pump in the field also, and that could allow you to move fluids at a higher rate. So we'll just -- we'll continue to monitor it, but couldn't be more pleased with the results today on the Crosby well.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Great. And then I thought it was encouraging to hear that Sinopec has elected to keep their 1/3 interest in the acreage you picked up from Devon. Just interested to hear if you've approached them or plan to approach them about expanding the JV to cover your entire TMS position?

Walter G. Goodrich

Yes, this is Gil. I think our first order of business with our new partner is to get out and drill some wells jointly and to hopefully demonstrate our operational capabilities and certainly, hopefully, some successful wells together. And at that point, if they have some interest in expanding that position, we certainly would be all ears and willing to listen to them.

Operator

Your next question comes from the line of Brian Corales representing Howard Weil.

Brian M. Corales - Howard Weil Incorporated, Research Division

And just on the acquisition, is there anything -- is there a lot of short time fuse on some of that acreage or do you all have kickers there?

Walter G. Goodrich

Yes, Brian, it's Gil. As I've tried to lay out as best I could, we do have time, there's nothing urgent. The vast majority of the acreage does have these built-in, fixed 2-, or in some cases, 3-year extension options, or what we refer to as kickers. Some of those are being paid currently and will continue to be exercised. We'll have the option to exercise them, really getting all the way through next year and into 2015. So we do not expect to lose any appreciable acreage unless we make an internal decision to not spend some acreage for at least the next couple of years. And then as we get to 2015, we'll obviously have to have a certain pace of drilling in order to continue to hold all of the acreage. As I said, some of it has got kickers that go longer than that, some of it's already held by production, some of it has continuous drilling provisions. So it's really a myriad of different things and almost impossible, at this juncture today, to say exactly how many acres ultimately we will retain. But it certainly is a possibility and we see an avenue there, if we have some incremental funding come in over the next 3 to 5 years, then we can hold the entire 320,000-acre position.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay. So over the next 12 months or so, you don't have to go at 2 or 3 rigs, having kind of -- okay.

Walter G. Goodrich

That's correct.

Brian M. Corales - Howard Weil Incorporated, Research Division

And then they either post these -- the Encana-operated wells and your Smith and Crosby, have you changed or plan to change anything on the completion from -- based on those results? Or are you happy with where you are today?

Walter G. Goodrich

I think we're very happy, Brian. John Freeman raised the question about the Anderson 17-2 and profit amount, and they did pump slightly higher profit amounts. I think they were gearing towards around 600,000 pounds per state and we were at about 453,000 pounds on the Crosby. So as long as we're not increasing fluid volumes and we think we might -- could get that much profit away per stage, we think that looks like a pretty good recipe. But other than that, we're going to stick with the exact recipe we've used on the Crosby and the Smith, and maybe tweak it further, what we've seen in the Anderson 17-2.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay. And then one final one. Based on your discussions with Encana, and I think Rob mentioned that there's other people that may or may not be coming into the play, I mean, do you get the sense that there is going to be an acceleration by industry, not just Goodrich, coming to the Tuscaloosa?

Walter G. Goodrich

Brian, it's hard to make a prediction. But I would say this. If thousands of 15,000 barrels a day wells continue to populate across this play, I find it hard to believe that there won't be some people taking some second looks at TMS.

Operator

Your next question comes from the line of Steve Berman representing Canaccord Genuity.

Stephen F. Berman - Canaccord Genuity, Research Division

Back to the Smith well, Rob. That 8-day period that averaged 1000, was that like days 8 through 16 or 20 through 28? Just trying to get where that is on the timeline.

Robert C. Turnham

Yes, there's a little bit of a gap when we switched from production testers through the equipment, that takes some time to transition there. We had the wells shut in a little bit from -- after probably 1 week. So I would say it's -- probably third week is the ballpark estimate on that.

Stephen F. Berman - Canaccord Genuity, Research Division

Okay, good. Just one more. In the Eagle Ford, after these lease explorations that made you let go, what's your current Eagle Ford position now?

Robert C. Turnham

We're at 32,000 net acres. We'll show that on our EnerCom presentation. And frankly, look, we just -- you get to a point, on the very northern portion of our block, we had extensions. But when you look at the potential that we have on the TMS, the size of that block, what we have left on our southern 60% of our block, which is clearly perspective. At the end of the day, we have better use of our capital to spend some money on some type of option value there on the -- where the Eagle Ford was a little more challenged. So that's was a fairly easy decision for us, and we'll continue to do that. If the acreage doesn't fit within our type curve or attractive economics, you could see us continue to let some of that more northerly acreage go, just do a better use of capital elsewhere.

Operator

Your next question comes from to the line of Subash Chandra representing Jefferies.

Subash Chandra - Jefferies LLC, Research Division

Do you have a total TMS production number now to the company? And do you think that's something, in 2014, you'd break out?

Walter G. Goodrich

Yes, Subash, this is Gil. We don't have that number for you yet. Obviously, it's still not a huge percentage of our overall production. But it obviously is growing. We have a very high working interest and high net revenue interest in the Smith well. We will in the CMR/Foster Creek well. As well as the Huff well, we plan to drill behind around that. So I think as we get into the fourth quarter, maybe in the wake of the fourth quarter, you'll start to see the TMS become a more meaningful piece. And yes, we will start to break that out for you, if not the fourth quarter, certainly the beginning of the first quarter next year.

Subash Chandra - Jefferies LLC, Research Division

Okay. And I guess you have these high-working interest wells and then, of course, the CapEx obligation with it. Is there a desire as quickly as possible to sort of balance that out with the Sinopec wells? Or do you actually -- would you rather have the Sinopec wells, partnered wells, dominate the development inventory?

Walter G. Goodrich

That's a good question, Subash. I think near term, it makes sense for us to get down that acreage. Obviously, one of the objectives is to try our wells, design our recipe on that acreage and see if we can turn that around. And having Sinopec hopefully participate with us, as we expect for a third interest, helps share some of the burden of that. And so we're going to move. And I would say, the move in the fourth quarter and the majority of our DMS activity in the fourth quarter will be on formally Devon acreage.

Subash Chandra - Jefferies LLC, Research Division

Okay. And what are the terms here if, God forbid, for whatever reason Sinopec does not consent. Of course, not suggesting at all that they would, but what are the terms here for them to come back in?

Robert C. Turnham

We have a standard joint operating agreement in place that kicks in as soon as we sign and finalize the deal with Devon, which have a standard 300% non-consent penalty to both parties can elect to. But...

Subash Chandra - Jefferies LLC, Research Division

Okay. And did they lose the well or the section -- a section of 640-acre? Or is that -- I think whatever refers to a larger section here.

Robert C. Turnham

The 300% non-consent penalty adds to that well.

Subash Chandra - Jefferies LLC, Research Division

Okay. And the final one for me. Could you describe the jet pump versus other types of artificial lift in terms of efficiency and costs?

Robert C. Turnham

I would say cost is very similar to rod pumps. If you were to put the big unit, you can spend anywhere from $200,000 to $450,000 on a big rod pump that can move a lot of fluid. The jet pump is not -- is probably at the low end of that, perhaps. So you're basically able to -- I think it's -- part of the technology is this Venturi effect where you create a differential downhole and you're able to move the fluid at a little bit higher rate, we think. That's -- you pump in with a fluid, such as water or propane, down a nozzle and create this kind of differential, and then you pull it out with the rest of that. So I think that's what we're focused on. Can we move fluid volumes more efficiently with the jet pump versus a traditional rod pump? That -- obviously, rod pump's hard [ph] and jet pumps have their own mechanical issues.

Walter G. Goodrich

Subash, this is Gil, let me pick up and add one thing to what Rob said, which is that there's less moving parts with the jet pump. We can move, generally, more fluid and total fluid with the jet pump being downhole, one of the problems with a jet pump is if you've got too much gas in the system, they really don't work very well, and so we think the TMS is ideally suited for that with the lower gas volumes and high -- 90%, 95% crude oil. So that's why we tried it on the Crosby. So far, so good. We're pleased with the performance, hadn't been in that long, maybe 1 month, or quite a month maybe. But so far, it looks good. And ideally, this is the type of pump to go, we'll just have to wait and see over time.

Operator

Your next question comes from the line of Pearce Hammond representing Simmons & Company.

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

I know it's still very early days in the TMS, but let me get your kind of broad thoughts on how you see the core of the play developing. I know it seems like we've had some very good results in any mine in Wilkinson County in Mississippi, but do you think that it extends further south into Louisiana, maybe a little bit east or whatnot?

Walter G. Goodrich

Yes, Pearce, this is Gil. One of the benefits that we have gained from the Devon transactions, we did pick up core data on all of the Devon wells in which they took course, which materially added to our knowledge base from a geologic perspective. We're not saying -- and we've said this publicly, we're not seeing anything more than what we would call very nuanced differences in geology and mineralogy and rock properties including clay percentages and types of clay. So we don't see anything -- and I guess we should back up and redistributing, the high redistributing, we do think is an important feature. A number of different things contributing to that. We probably see the highest redistributing, quite frankly, across the southern part of the play in Louisiana, right along the southern part of the Mississippi-Louisiana border there. So we're optimistic, we need to get down there and demonstrate what we think it is capable of. But we're not seeing anything, at this point, that rules out any particular part of the acreage. The geologic changes or some nuance is small. And in fact, if you look at the Crosby, it's probably got the highest -- one of, if not the highest, clay content of any of the course we've seen across the play. So everything is open and on the table in our mind.

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

Gil, that's helpful. And then my follow-up is on the severance tax reduction in Mississippi, which is helpful to the economics, how long is that in effect?

Walter G. Goodrich

It's 30 months or until the well pays out. And we believe that's on the order of $750,000 to $800,000 of benefit to the well. So very important and very meaningful.

Operator

Your next question comes from the line of Mike Scialla representing Stifel.

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

Just wondering, you were willing to put out a preliminary rate on the Crosby as it was cleaning up. And wondering your thought process on why you weren't willing to do that for the Anderson 17-3. And you also -- you said that you think it that's going to be a good well. What's that based on?

Robert C. Turnham

Well, early flowback is what it's based on. And look, that's an Encana-operated well, and the Crosby was our operated well, so we have full control over what we say on the Crosby. So I think just be patient. It's coming. And as Gil and I both said, we're optimistic that's going to be another good well. It's just -- it's a longer lateral and it started to flow back later, and so we just need to get the sufficient flow load recovery before we see the peak rate.

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

Okay. And anything you can say on those ash wells at this point? Or do you think that they are really not relevant, given that there was a different completion technique used on those?

Robert C. Turnham

Yes. I mean, we certainly think they're not as relevant as the wells with the proper completion technique. We're just seeing material differences when using the proper amount of fluid, in particular. There may be an opportunity to improve the well results, pumping more sand, like Gil suggested, and we're certainly seeing EOG and others do that, shorter laterals with more sand and just better and better wells. So that clearly is a possibility. But the fluid is important. And at least, in our opinion, the ash wells, which had twice the amount of fluid pumps, that certainly can impact your initial flow rates. While pressure is coming down, you have a hard time outrunning the water production or the frac fluid production. So in this play, as Gil I think said perfectly well, it's all about the completion recipe and landing zone and then proving up the economics through guiding well costs down.

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

Do you think the fluid type has anything to do with it, or is it pretty much just the quantity of fluid that was pumped there?

Robert C. Turnham

No question the hybrid frac, in our opinion, work a lot better than slick water. And as Gil said, the clay stabilization fluid that we pump, you cannot argue is working extremely well. The first one to pump that particular type was the Crosby well. And when you look at lateral links and profit amount pumped and how those wells were completed compared to others, that well is certainly superior to the other ones. So we think that's an important ingredient to put in the recipe.

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

And I just have one last one on the Eagle Ford. At this point, it sounds like it was a pretty much a timing issue. Any thoughts, or need to change your Eagle Ford type curve? Are you still comfortable there with -- I think you have 425, if I remember correctly?

Robert C. Turnham

Yes, we've just done that and we're going to show an update, and it's consistent with our previous EUR. The shape you -- when you drill wells in between wells you may not see the same high peak rate, but it does create a flatter curve. But you'll see at EnerCom next week, the composite curve is very similar to what we've already had.

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

And I guess what -- I lied there, I have one more. In terms of what you had embedded in your original forecast for the Eagle Ford oil production, what really surprised you there? It sounds like it was -- you saw more interference than you originally were anticipating, is that a fair assessment?

Robert C. Turnham

Yes, this is Rob again. Yes, I would say that we underestimated the aerial extent of the fluid when pumping these frac jobs. One way to look at it this we, in essence, have kind of waterflooded an area, it's going to produce, we think, very well by virtue of fully stimulating that entire area. But no question that it's impacting wells more than 1 or 2 offsets away, in particular when you're drilling in the middle of an area where you've had wells along the perimeter, and that's basically what we've done in this particular area.

Walter G. Goodrich

Mike, this is Gil. I'll just add one comment. I always hate to try to take a negative and turn it into a positive. But in fact, what surprises is the distance away from these newly frac-ed wells that we are seeing frac water interference. And in fact, we are telling ourselves that we've really got that section of the Eagle Ford really busted up quite well, and we think, ultimately, once we get the induced water completely off and can leave that area alone and let it heal, we're actually going to see better recoveries, overall, because of the intense frac-ing that has taken place in there.

Operator

Your next question comes from the line of Ron Mills representing Johnson Rice.

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

Guys, just maybe an adjustment on one of Pierce's questions about the differences in acreage. The Smith well versus the Crosby was 36 miles to the east, any real differences in the geology or thickness or clay content between those wells? Or is the comment similar as to what you suggested that even down through the Devon acreage, you're not seeing major differences between the rocks?

Walter G. Goodrich

Yes, Ron, this is Gil. As I said, we're seeing very, very slight nuanced differences. Very difficult for any of us, internally, to point at any one thing. It's driving it based on geology or mineralogy or rock makeup. So the percentages of clay content and the types of clays within that are pretty much in line. I think once we get beyond some confidentiality requirements, we might be able to sit putting some of that out and demonstrate to the public the very slight differences. So, again, really difficult for us to start ruling anything out or anything in this point. I think the drill bit is going to have to determine that, but we feel very optimistic because the entire play in the acreage we own has perspective nature to it.

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

And is that opinion a little bit different than what you thought when you announced the Devon acquisition, where I think you had said that maybe up to 25% of the Devon acreage may not have the characteristics you're looking for? Has that changed now because you've looked at more core data, or am I remembering that incorrectly?

Walter G. Goodrich

Let me clarify that. When asked about how much acreage you, potentially, if you were having to handicap it, to maintain, I think the comment was at least 75% of that was either shallow, above 14,000 feet through vertical depth, so your well costs would be lower, or in -- what we view could be core and less on the fringe of the outskirts. So that was basically just an attempt to handicap it if we could. We don't see anything but subtle differences when you look at core data, not only from the Crosby all the way into the Devon acreage package. We think it's all in the completion recipe. So no, nothing has changed. Certainly, once we got into the data room and we were able to review the data, we became more positive about the Devon acreage. But no, we were just trying to handicap at that point in time. But as Gil said, we can't rule out any of the acreage at this point.

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

And on the Smith well, I know the usable lateral was less than the drilled lateral. You had, at least, as of initial release, not drilled out the remaining 6 or 7 plugs. Have you now done that or is that still to come? I'm trying to judge where this current 1,000 BOEs per day is versus the IP rig versus those -- the plugs that didn't get drilled out initially?

Walter G. Goodrich

Yes, Ron, this is Gil. We do have some plugs in there. And I think our current thinking around that is that a few months down the road and once we get ready to run permanent tubing in the well and obviously before we want to put it on pump, whenever that may be, down the road, we'd go in, put a rig on it, go in and attempt to drill out the rest of those plugs. But right now, it's flowing with those plugs. And then, of course, the frac plugs that are in there are built to float through the plugs. So we trace each of the zones, we are getting contribution from all of the zones even those that are out behind the remaining plugs. We're comfortable with the way it's performing at this point.

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

Okay. And then lastly, just -- can you dumb down, Rob, the clay stabilizer, what it's doing? And is this something that's relatively new that you're applying to the TMS that people may not have thought of 1.5 years ago? You're the first one I've really heard talking about it as much, especially with the Crosby well having as much clay, but seems to be offsetting those concerns. Just any more color on that would be great.

Robert C. Turnham

Yes, without talking specifics as to what the actual fluid is, when you look at the data, in fact the Crosby has higher clay content that almost any well out there, and you look at how that well has performed versus the other wells, knowing that we pumped this particular type of stabilizer and it's just the fluid that you include in your frac fluid, you can't rule out the fact that that well has performed exceptionally well. And it's just basically a pump to keep the expendable clay portion of the overall clay from swelling. And if you can keep it from swelling, it becomes less sponge-like, you get a more effective frac, you get your fractures propagated and held open, it doesn't want to close up on you. So it's a fairly simple, I would say, process. And we had quite a bit of lab work done and analysis done, and we felt like this potentially could be as much as 75% more effective -- at least that's what some of the lab work had indicated. So yes, we're pleased with it. And of course, the not going in was whether the clay would impact these -- the production, and we're not seeing the impact of clay on any of the wells. But certainly, the Crosby, and these last 2 wells, are performing exceptionally well with the pump.

Operator

Your next question comes from the line of Matt Portillo representing Tudor, Pickering, Holt.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Just 2 quick questions for me. In terms of the Crosby well, I was wondering if you could give us a current oil cut on the well. And then -- and secondarily, just on some of the wells where you have longer-term data, particularly the Horseshoe and Anderson 17H, which are kind of close to your base-type curve, could you give us an update on how those are performing relative to expectation?

Robert C. Turnham

I'm glad you asked that question, Matt, because I was curious as what your type curve is relative to 375 barrels equivalent per day. I saw that in your notes today. But no question, as I explained, the Crosby is outperforming our 800,000-barrel curve. The oil cut is about 92% there, and that's been fairly consistent. I think it started at 90%, but we've seen the oil hold up slightly better than gas. As to the Horseshoe Hill and the Weyerhaeuser, we are updating those curves and we'll include that in our EnerCom presentation next week. So we'll be able to show how those wells correspond to those curves. But again, what we would certainly point to is that early well results without the optimum completion recipe, certainly look different than what the more recent wells do that have pumped the proper completion recipe in our attainment.

Operator

Your next question comes from the line of Louis Baltimore representing Macquarie.

Louis Baltimore - Macquarie Research

I just got one quick question. I guess despite the improving stream of data point in the TMS, you were able to buy a bigger acreage block for essentially under $150 without ascribing any value to PDP reserves. So can you comment on why the -- and I guess, what was responsible for the block trading at such a low valuation metric without much competition from other operators in play?

Walter G. Goodrich

This is Gil. I would say that not that many of the people view the play the same way we do. And when the price got down into our strike range, we went after it. And I will let everybody else comment for themselves about why they didn't pursue it.

Operator

At this time, I would like to turn the call back over to Mr. Gil Goodrich for closing remarks.

Walter G. Goodrich

Thank you, everyone. We appreciate your participation this morning. We've got a lot of exciting things on the play, and we look forward reporting those to you when the third quarter is completed. Good morning.

Operator

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect, and have a great day.

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