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Goodrich Petroleum (NYSE:GDP)

Q4 2012 Earnings Call

February 21, 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

Michael Kelly - Global Hunter Securities, LLC, Research Division

Ryan Todd - Deutsche Bank AG, Research Division

Brian M. Corales - Howard Weil Incorporated, Research Division

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

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

Dan McSpirit - BMO Capital Markets U.S.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

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

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

Joseph Patrick Magner - Macquarie Research

Operator

Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2012 Goodrich Petroleum Corporation Earnings Conference Call. My name is Kim, and I will be your operator for today. [Operator Instructions] As a reminder, this call is being recorded for replay purposes. I would like to turn the call over to Mr. Gil Goodrich, Vice Chairman and Chief Executive Officer. Please proceed, sir.

Walter G. Goodrich

Thank you, Kim. Good morning, everyone, and welcome to our year-end 2012 earnings call. With me here this morning is Pat Malloy, the company's Chairman of the Board; Robert Turnham, our 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 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, and which involve risks and uncertainties, and we have detailed for those -- for you in our SEC filings.

During 2012, we continued our transformation from a company with reserves and production dominated by natural gas towards a more balanced portfolio of assets and a company with maximum flexibility that would allocate capital to high-return projects in either crude oil or natural gas. While we still have considerable progress to be made, we achieved the vast majority of our corporate objectives in 2012.

As we entered last year, crude oil, on an Mcfe basis, averaged just under 15% of total production. In the fourth quarter of 2012, crude oil volumes grew by 12.5% sequentially over the third quarter and equated to 30% of total production on an Mcfe basis. On an absolute basis, net crude oil production was 1.1 million barrels in 2012 or a 70% increase over 2011.

For this year, we have -- are again forecasting another 40% to 60% increase in crude oil production volumes. The increase in crude oil volumes are driving a further expansion of our operating cash margin, which increased to 75% or $7.35 per Mcfe on adjusted oil and gas revenue, including our realized gains on derivatives of $9.83 per Mcfe in the fourth quarter of last year.

The increase in oil volumes and cash margin expansion led to a company record in EBITDAX of just over $50 million and discretionary cash flow of approximately $40 million in the fourth quarter.

As we have stated before, we do not believe current natural gas prices justify drilling for dry natural gas reserves, and as such, all of our 2013 drilling plans are associated with our oil-rich Eagle Ford and Tuscaloosa Marine Shale plays. While we are making good progress in our transformation to a much more balanced reserve mix, we are still a company with a majority of our reserves in natural gas at year-end 2012. As such, the SEC trailing 12-month natural gas price of $2.85 per MMBtu impacted SEC proved reserves, where we incurred negative reserve reversions, almost exclusively associated with low natural gas price and undeveloped dry gas reserves. As a result, proved reserves under the SEC pricing declined to 333 Bcfe after giving effects to the reserve revisions as well as the sale of our South Henderson assets, which occurred in the third quarter of 2012.

However, looking forward and using current 5-year strip prices of $4.17 per Mcf and $90.13 per barrel, year-end proved reserves would have been 442 Bcfe, with a present value discounted at 10% of $530 million.

The low natural gas price environment also impacted our income statement at year end, where we incurred a onetime noncash charge or impairment of approximately $47 million primarily associated with property in East Texas and related to the Haynesville Shale.

In the Eagle Ford Shale, our drilling team again turned in impressive results in total average feet drilled per day. In the second half of 2012, our team achieved what we believe are industry-leading drill times and spud to rig release of approximately 10 days per 10,000 feet. These results are allowing us to increase wells per -- drilled per rig and reduce overall completed well costs.

In addition, we believe the lessons we have learned in the Eagle Ford will be very valuable as we increase our activity in the Tuscaloosa Marine Shale play and work to reduce cycle times and total completed well costs in this new emerging oil play.

In addition, in 2012 -- our 2012 Eagle Ford activity, where we drilled 33 gross, 22 net wells and invested approximately $173 million, was the primary driver behind our 70% increase in crude oil production during the past year. As I previously stated, we expect crude oil volumes to grow again in 2013 by approximately 40% to 60% over 2012, and our planned Eagle Ford activity will play a meaningful role in this year's oil production growth.

Our liquidity position and balance sheet remains in good shape. We exited 2012 with $95 million outstanding under our senior credit facility. Borrowing base under the credit facility is currently $210 million, giving us approximately $115 million of liquidity at year end. Our year-end reserve report, which includes all the wells drilled in the second half of 2012, which was almost exclusively oil-directed activity, will now be delivered to our senior bank group, and we expect to have a newly redetermined borrowing base shortly after the end of the first quarter.

In addition, while the first put call date on our 5% convertible notes is not until October of 2014, we will initiate steps to address these notes prior to the end of this year.

And finally, moving to the Tuscaloosa Marine Shale. Rob is going to give you a very solid update on the play, but before he does, just a few comments from me.

While the Denkmann well suffered a series of frustrating mechanical issues that prevented us from being able to produce the well and resulted in a meaningful charge to exploration in the fourth quarter of last year, we do and plan to come back and develop this acreage at a later date.

We are extremely pleased with the performance of the Crosby 1H well, which continues to outperform our expectations. The combination of the Crosby early time performance and the increasing age of the older longer lateral wells has further increased our confidence in the preliminary range of EUR expectations, and Rob will share those with you in just a second.

In addition, our Crosby well is located in Wilkinson County and is approximately 25 miles west of the EnCana Anderson wells in Amite County, Mississippi. Therefore, the Crosby well represents another significant data point further delineating our large acreage position in the TMS.

Finally, while we still have work to do, our knowledge of and solutions for the drilling problems experienced by a number of early wells in this play is improving, and we are increasingly confident that we will continue to see improving drill time results and improved total well costs in the TMS in 2013.

With that, I'll turn it over to Rob for an update on the TMS.

Robert C. Turnham

Thanks, Gil. Needless to say, we are extremely pleased with the results from the Crosby well in the TMS. As we mentioned in the release, the well peaked at an average 24-hour rate of approximately 1,300 barrels equivalent per day on a 15/64-inch choke, with approximately 1,200 barrels of oil and 600 Mcf of gas per day. The well has averaged 1,200 BOE per day over 15 days from a similar choke size, and is currently producing at that same rate.

Based on the current production trend, we expect the well to produce in excess of 30,000 to 33,000 barrels of oil in the first full 30-day period. This well is capable of producing at a much higher rate on a more open choke size, but as we have seen in our other shale plays, we feel it prudent to maintain a conservative early flowback plan, which will maintain maximum reservoir integrity.

We are very confident of the resource potential of the play. We're plotting production data from public sources. The Anderson 18 well has reached cumulative production of approximately 100,000 barrels of oil equivalent in approximately 7 months of production, which is significantly better than industry performance in the oil window of the Eagle Ford and compares very favorably to upper tier Bakken wells, which reach a similar amount of production in about 12 months.

Factoring in current LLS pricing of approximately $115 a barrel and 20% royalty, we generate gross and net revenue of $11.5 million and $9.2 million, respectively, in approximately 7 months.

The Anderson 17, which has a shorter lateral length by approximately 1,400 feet than the Anderson 18, has reached cumulative production in excess of 80,000 barrels of oil equivalent in 7 months, which is similar to many of the best Bakken wells at roughly the same point in time.

TMS production is approximately 90% to 95% black oil, priced off of LLS, which has a current uplift of approximately $20 over WTI. So as I described earlier, these BOE production numbers are significant, not only from a well performance basis, but in cash flow generation.

We now have approximately 8 to 13 months of production from the recently drilled and properly stimulated TMS wells, which production profiles have all gone hyperbolic, with the rates of decline flattening considerably.

As a reminder, in all shale plays, you typically see wells go hyperbolic beginning around months 6 to 9, and the TMS is no different. The wells to-date have also been flowing a 5.5-inch casing over the first few months, and we feel by running tubing earlier in the life of the well, we can improve early production rates and rates of return going forward.

When evaluating public data, we have generated preliminary type curves ranging from 400,000 BOE per well on short laterals to as much as 800,000 BOE per well on longer laterals, such as the Anderson 18 and likely the Crosby, which to-date has tracked above the Anderson 18 even though the lateral length is approximately 2,000 feet shorter and the well had 5 fewer frac stages.

Through 8 months of production, the Anderson 17 is tracking our mid-case type curve of approximately 600,000 BOE. We would obviously like to see more wells and more history from these wells to feel comfortable with these type curves at this point in time and believe they establish a solid range of potential EURs.

In addition to commercial rates of production and higher oil pricing, the play has certain additional inherent advantages, such as: Number one, our gas has a very high BTU content with 8 gallons of NGLs per million cubic feet of gas, which calculates to approximately 190 barrels of liquids yield per million cubic feet of gas produced; Number two, we have a 5% lower royalty burden in this play than what we have in the Eagle Ford, with average royalty across our acreage of approximately 20%; Third, we have a 2-year severance tax abatement on our Louisiana wells and expect something similar in Mississippi; And fourth, we have very little infrastructure and surface constraints, in that the oil is trucked from the lease for approximately $2 per barrel differential off of LLS pricing, and our acreage is located in a rural area with supported landowners.

Most of the wells drilled to date have either had drilling issues caused by well-bore instability from a specific 10-foot interval which we call the rubble zone or has been drilled and evaluated with a considerable amount of science performed on the well, like the Crosby, where we drilled a pilot hole, logged, cored and evaluated the formation.

Our coring of the Crosby indicates the quartz content in the lower half of the TMS comprises approximately 50% of the formation and the clay content is lower, both of which are positive indicators of a higher-quality source rock.

Going forward, we think we will take our current well cost estimate, without science or drilling issues, of $12.5 million to $13 million to $10 million to $11 million over time for a production and drilling days, better service company pricing due to increased capacity in the field, pad drilling, zipper fracs and other efficiency gains.

When factoring in our mid-case type curve of 600,000 barrels equivalent, which is again, driven off of production data from the Anderson 17H well, and using a $13 million completed well cost and $90 WTI pricing, we are projecting close to a 40% rate of return, which is very competitive with other nonconventional oil plays.

As we drive costs down, we expect to see an incremental 10% to 15% improvement in IRR for every $1 million of cost savings. And if we can hit our target of a $10 million completed well cost, we would generate in the neighborhood of a 75% internal rate of return.

In all of our horizontal plays, our drilling team has demonstrated the ability to reduce costs over time as they nail down the specific best practices for each area. This is confirmed by looking back at each of our primary plays and tracking drilling days to total depth.

For horizontal Cotton Valley wells, we started at 48 days spud to TD when we first got started, and ultimately wound up at 36 days when we finished. Our Haynesville drilling went from 46 days to 33 days spud to TD, and our Eagle Ford from 23 days to 10 days spud TD. When we reduce the drilling days in the TMS, and it will happen, we expect a cost savings of $90,000 to $100,000 per day. So for every 10 days of reduced drilling time, we expect to generate an approximate $1 million of savings.

Pad drilling, service company capacity additions, zipper fracs, et cetera, should provide the additional savings over time to allow us to reach our target well cost.

In other activity in the field, we have a 12% interest in the Ash 31-1 and 31-2 wells, both of which landed above the rubble zone and are currently being frac-ed, as well as the Anderson 17-2 and Anderson 17-3 wells, with the Anderson 17-2 well currently drilling, to be followed by the 17-3 well.

Given our increasing confidence in the play, we are accelerating the timing of our next operated well and expect to spud the Smith 29-1 well in April.

We will roll out TMS slides in our management presentation next week as the conference season kicks off in earnest, which will exhibit the data I just gave you and I think show you why we are encouraged about the play and development potential of our 135,000-acre block.

Focusing on the results for the quarter. Production was 6.6 BCF equivalent with average production of 3,600 barrels of oil and 50.3 million cubic feet of gas per day. Our volumes were negatively impacted by the mechanical issue on the Denkmann well, which is scheduled with a future development location.

We currently have one 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, and an estimated 20 days spud-to-spud. Current plans have us drilling at the lower range of the 24 to 28 wells budgeted due to spending at the higher-end of the budget in the TMS. We continue to monitor Pearsall Shale production in the area, with tentative plans to spud a well later this year.

We continue to hold all of our natural gas acreage in 6.5 TCF of resource potential with very little CapEx for the year. The vast majority of our North Louisiana and East Texas acreage is either held by production or subject to lease extensions, which gives us great flexibility on allocation of capital to the highest rate of return projects while maintaining huge leverage with an improving natural gas market.

In closing, the Eagle Ford and TMS will continue to drive our oil volume growth through 2013 and beyond. The improved efficiencies and reducing drill times and well costs in all of our plays have us confident that the same will occur in the TMS, which will unlock significant value for the company.

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

Jan L. Schott

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

Revenue for the quarter totaled $48.2 million. If you include the realized gains on derivatives of $17.1 million with our reported revenue, adjusted revenue for the quarter was $65.4 million, an increase of $4 million or 7% over the adjusted revenue for the comparable period last year and $0.6 million or 1% over the adjusted revenue for the third quarter of 2012.

Our fourth quarter average realized prices, excluding the impact of realized gains on derivatives, were $98.63 per barrel for oil and $3.31 per Mcf for natural gas. If you include the impact of realized gains on derivatives, the average sales prices were $110.12 per barrel for oil and $6.20 per Mcf for natural gas. This represents an $11.49 per barrel uplift in the price for oil and a $2.89 per Mcf uplift in the price for natural gas.

Our plan is to continue to layer on additional oil derivatives as we increase oil production during 2013. We also continue to watch natural gas for an opportunistic time to hedge portions of our 2013 and 2014 natural gas production. Please see our website for an updated slide on our current derivatives 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 $0.71 below the prior quarter rate, as the fourth quarter includes certain nonrecurring adjustments. The fourth quarter includes about $0.13 for workovers. If you exclude workover costs, our LOE rate per unit would have been $0.58 for the fourth quarter. The LOE rate per Mcfe was $0.83 year-to-date. And if you exclude $0.14 for workover activity, the LOE rate would have been $0.69 for 2012. As we have stated before, as we increase our oil production, we would expect our LOE rate per unit to gradually increase over time.

DD&A per Mcfe was $5.62 for the quarter, compared to $4.80 last quarter and $3.87 for the prior year quarter. The higher DD&A rate compared to last year is related to more oil production from the Eagle Ford Shale, which carries a higher F&D cost per Mcfe than our natural gas properties. About 34% of our total production came from the Eagle Ford Shale in the fourth quarter, as compared to about 25% in the third quarter of 2012 and 16% for the prior year quarter. We would expect this trend to continue as we increase oil production in 2013.

Also, the fourth quarter does not include production from our South Henderson field, which was sold in the third quarter of 2012. This field carried a much lower DD&A rate per unit.

Exploration costs for the quarter includes a nonrecurring expense of $12.8 million or $1.95 per Mcfe for the Denkmann well mechanical issues that Gil discussed earlier.

In the fourth quarter, we recorded impairments of $45.2 million, primarily related to our East Texas Haynesville property -- properties as a result of low natural gas prices.

G&A costs per Mcfe came in at $1.09 this quarter compared to $0.92 last quarter. Cash G&A per Mcfe came in at $0.76 in the fourth quarter compared to $0.70 for the third quarter of 2012. About $0.33 or 30% of the fourth quarter total rate represents noncash stock-based compensation compared to $0.22 and 24% last quarter.

We are projecting a 0 tax rate for the full year of 2013. We are also confirming the previous CapEx guidance range of $175 million to $200 million for 2013. Following the success of the Crosby TMS wells, we expect Eagle Ford Shale at the low end and TMS at the high end of 2013 CapEx ranges previously given.

As Gil stated, at year end, we had $95 million drawn under our senior credit facility, which has a $210 million borrowing base. Adding in $1 -- or I'm sorry, $1.2 million in cash for a -- makes a total of $116.2 million in liquidity at year end. The next redetermination of our borrowing base will occur in April 2013 in conjunction with our year-end 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 2012 annual report on Form 10-K with the SEC tomorrow. Please see our 10-K 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. Our strategy for 2013 is very well-defined and balanced. We will remain focused on consistently growing crude oil volumes, preserving our large natural gas footprint for the future with little to no addition capital, maintaining ample liquidity, incrementally strengthening our balance sheet and increasing the development of our Tuscaloosa Marine Shale play.

With that, I will turn it back over to Kim for Q&A.

Question-and-Answer Session

Operator

[Operator Instructions] And your first question comes from the line of Mike Kelly with Global Hunter Securities.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Rob, with your extremely compelling TMS comments, and I just kind of wanted to -- if we took down the list of things that you've already accomplished and the industry's already accomplished in the play, disproven that clay was going to be an issue, that was the first big scare. You've figured out the proper completion technique to get a really strong first month rate. You now seem to have the history that supports cumulative production stacking up even better than what's conceived to be the best oil plays in the country. You've got line of sight to get drilling costs down to $10 million a well. What is left to prove, in your eyes, to get you to come forward to the market, do a JV and really garner a strong price that we've seen in some other basins?

Robert C. Turnham

Yes, Mike, thanks for that question. I think more wells spread out and little more history would be helpful, but we're pretty comfortable, especially when the analog is the Eagle Ford in our type curve analysis to date. We would expect perhaps some variability across the play, whether it's north or south or east or west, but the good news is, is that, as Gil said, these wells are 25, 26 miles apart, between Anderson and the Crosby wells, and we have a huge percentage of our acreage, obviously, is in Mississippi and in those areas. So I think more wells and more history from those wells will clearly be helpful as to determining whether there's any variability across the play. But as we've said before, our plan is to drill the initial well, delineate the acreage and bring in a -- either a financial partner or an industry partner at the right time, at the right price, and this certainly strengthens our hand.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Got it. And if we could just talk about the timing of the next incremental data points, you had mentioned your well, the Smith well and then the EnCana well that you have working interest in, should we expect to have press releases out on those EnCana wells, just to kind of monitor the progress there?

Walter G. Goodrich

Yes. Mike, this is Gil. As Rob said, we are currently frac-ing the 2 Ash wells. Those wells will be frac-ed back-to-back. We do have an interest of about 12% in both of those wells, so as soon as that data is available, we would put that out. I don't know exactly what that will be in terms of the ultimate timing, but let's call it the latter part of March, second half of March feels about right. Anderson wells are currently being drilled. We don't -- do not know the specific timing yet of the frac schedule or when those wells will ultimately be done, but I would move that back probably another month, 1.5 months, so late April to the first part of May would be the best guess we could give on that at this point in time.

Operator

Your next question comes from the line of Ryan Todd.

Ryan Todd - Deutsche Bank AG, Research Division

First question on costs. I mean, how should we think -- there's been a lot of science involved, both on your part and on EnCana's part, so far on the drilling. As we think over the course of the rest of the year, how should we think about the transition from science-driven wells to more development-type wells, from a timing point of view? And for example, the Smith well, is there anything different that you're doing in the Smith well than in the Crosby well as well?

Walter G. Goodrich

Sure. Well, I think -- this is Gil, by the way. We think that a lot of the science has been done. There may be a few other places that we might decide to drill some pilot holes and take some additional core data. But to a large degree, I think we've kind of accomplished that. So I think you can generally think about us drilling wells without pilot holes. If we do the best we can on the Crosby, of trying to normalize that back to what we have done there had we not had the science and the pilot hole, we come up with about a 45-day cycle time, is a pretty good estimate to what it would have been, spud to TD. That would kind of get us back in the upper range of where we think current costs should be, which is, call it $12.5 million to $13 million. So I would say the next kind of leg down, as Rob kind of talked about in detail, was the anticipated improvement on cycle times, improving the drilling and the bit selection, downhole assemblies, working around the rubblized zone. We see those as kind of the next leg. And if we could certainly drive that from, say, 45 days down to 35 days in the next 6 to 12 months, then you're starting to, as Rob said, shave $1 million off of that and perhaps get down to something under $12 million. One of the things we're most encouraged about, however, is based on the performance and the preliminary type curves, even at $13 million and something even remotely close to where current LLS pricing is, we think we're generating very substantial rates of return.

Ryan Todd - Deutsche Bank AG, Research Division

And then if I could ask a follow-up on the type curve. Would you be willing to say, I mean, I -- what you think the decline rate, maybe like the first 12-month decline is on the type curve?

Walter G. Goodrich

Well, as Rob said, we plan to roll out our type curves. We'll have a 3-curve presentation, which will come out on Monday, in our management presentation, so you'll be able to look at that and see exactly what the decline rates are.

Operator

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

Brian M. Corales - Howard Weil Incorporated, Research Division

Just kind of digging down, maybe in a little bit more details, on your second operated well, what are you all estimating on drilling time?

Walter G. Goodrich

Yes. So the Smith well, Brian, is roughly about 40, 45 days drill time, it'd be in front or inside, it's probably in the higher-end of that, that 45-day spud to TD. Hopefully we'll come inside of that.

Brian M. Corales - Howard Weil Incorporated, Research Division

Right. Okay, okay. And can you -- I know you did some -- a little bit of testing, but is that about what the Crosby was and maybe on a normalized basis?

Robert C. Turnham

I can tell you -- this is Rob. I can tell you a well that is interesting -- one of the Ash wells that's currently being frac-ed by EnCana, which is -- it didn't have the science in it. Had we gone ahead and frac-ed that well similar to what we did on the Crosby well, we think we could be in the $12 million to $12.5 million range, certainly not north of $13 million. Then they're going to pop a bigger frac job, has been published on the, I guess the Tuscaloosa blog. But I think that's -- assuming that well stimulates similarly to what we've seen when landing below the rubble zone, then we're likely to land above the rubble zone on the Smith well, and if that's the case, that's probably a good potential marker in the $12 million to $13 million range.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay. And I mean, I think what I'm about to ask has been asked by everybody in different ways, but I mean, it seems like -- I know it's extremely early and the results thus far have been, I guess, much better than the market and most have thought. What is your worry now? I mean, is there a worry that at least a good portion of your acreage doesn't work? Is there a portion that it's not economic? Is it truly a cost issue? Do you all really have a worry?

Walter G. Goodrich

Well, Brian, it's Gil. We always have worries. We're paid to worry. So yes, we have worries. But we're -- as we've been saying and trying to say, as clearly and concisely as we can, that we're very encouraged by what we've seen. As we look geologically, and as we've said at the very beginning, before we bought our first acre, we did an exhaustive study of some 300 wellbores that had drilled through the TMS, chasing the lower conventional play. And we see broad consistency of at least thicknesses and log responses. What we don't know, I guess, is specific point-to-point. What is exactly the mineralogical makeup, and are we going to see a 50% quartz-type composition, which we think is a very positive indication of source rock, across the entire play. We can't fully answer that. We have seen it in several places now, so we're encouraged. Secondly, we have a very quiet, stable deposition environment here, which lends to very broad deposition without dramatic changes in rock properties. So that's an encouraging point. If you just ask me, I'd say the number one concern is moving from where we are today to shaving off another couple of million dollars of drilling costs. We're confident we'll do that over time, exactly when and how it occurs is a bit of a question. But clearly, that's a big focus for us. We're delighted with what we've seen in the well performance, and the only thing we got to do now is just get the costs down a little bit.

Operator

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

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

Obviously, a lot of TMS questions have been asked here. I think on EnCana's recent conference call, they talked about $15 million well costs, and you guys kind of referenced $12 million to $13 million. Any idea on what the potential disconnect may be there?

Walter G. Goodrich

Yes. We can't comment, obviously, on what they said other than we read it like everyone else did. And I believe, if you read the wording, what they said was they were budgeting $15 million. And we typically try to build some cushion into our budgets as well, so that our -- so that we can come in on our CapEx budget. We can say, on the other hand, which we're -- much of which is public data in Mississippi, we're seeing proposals and AFEs that are in the $12.5 million to $13 million range. So we don't know why they would be saying $15 million, other than that's what they included in their budget. They may be planning, as Rob mentioned, to pump some higher proppant jobs in an idea of bringing up performance even higher than what we've seen so far. But we'd have to direct you back to them for further answers.

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

Okay. So when you reference the AFEs for $12.5 million to $13 million, that's wells that you're participating with them in as well, right?

Walter G. Goodrich

That's correct. And that would be targeting about a 7,000- to 7,500-foot lateral and roughly, 25 frac stages, pumping something on the order of about 450,000 pounds of proppant per stage. If you want to go longer than that, add more stages or pump more proppant, obviously, the costs will go up.

Operator

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

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

To follow up on what you just said, Gil, the 450,000 pounds per stage, it sounds like EnCana is talking about using a lot more proppant in the Ash wells. What's your thought process regarding the 450,000 pounds versus the 750,000 to 1 million pounds per stage? And if you look at it, what do you think the difference would be in, on a per stage completion, between those 2 methods?

Walter G. Goodrich

Yes. So Ron, this is Gil. We would say that we've obviously, looking at the Crosby, are pretty delighted with 450,000 pounds of proppant. That being said, what we have witnessed today, through all the wells in the play, would be that as proppant amounts per stage have gone up, trying to otherwise compare in apple-to-apple in terms of lateral lengths and numbers of stages, you have seen improved performance from the wells. So thus far, there's somewhat of a linear correlation there, and we think it makes perfectly good sense to go ahead and test the upper limits of that correlation to see, can we add a little bit more cost for significantly better wells. And we think that's a worthy exercise and are fully supportive of that. In terms of the incremental costs, it's going to depend on exactly where you land in terms of additional proppant. If you went from 450,000 to say 750,000, you're probably adding $35,000 to $45,000 per stage of additional costs. If you went up to 1 million pounds of proppant or even over that, you're probably looking at $50,000 to $60,000 of additional costs per stage. So I think we're -- we would look at a bigger job, significantly bigger than a 450,000-pound proppant per stage job as science at this point, and let's just see how the results come in.

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

And what -- if you look at your $13 million -- or $12.5 million to $13 million, I guess I'm trying to back into this, how much is drilling versus completion? And how does that break down on your per stage completion cost?

Robert C. Turnham

Yes. Ron, I think -- and, of course, there's more completion cost over and above just the stimulation portion, but we're kind of running 40% drilling, 60% completion, currently. And then obviously, that would be skewed to the upside, if you're pumping bigger frac jobs. But call it, 135,000, 140,000 per stage, depending on how much fluid and proppant you pump. Yes, and then as Gil said, incrementally, over and above that depending on how large you pump. So for us, the one thing we can control the most, I think going in, is just best drilling practices and shaving days. And as I said in my prepared remarks, we've done that in every one of our plays, and no question, feel like we'll do that here as well. But we're having to contract with service providers who are having to drive in from other areas, and that's certainly increasing the cost of services. And once the play has proven up, that incremental capacity will help drive down cost there as well. So I think we've got a couple of -- or 2 or 3 areas that are going to drive the cost down. Pad drilling, just like we've seen in the Eagle Ford, will also take it down another leg, between skidding rigs and combining surface facilities, to zipper fracs, all the efficiencies you gain from doing that will help us drive that incremental cost down.

Operator

The next question comes from the line of Dan McSpirit with BMO Capital Markets.

Dan McSpirit - BMO Capital Markets U.S.

Rob, I was hoping you can review for us points made earlier in the prepared remarks, on the flattening of the production curve based on your observation of production history from other wells. I ask because it's really not a small point. And are you observing that the wells really are turning hyperbolic, maybe sooner than later, and if you could, express a B factor?

Robert C. Turnham

Yes, I'll tell you what we -- in the slides, there's going to be a lot of proof in looking at those slides, as to the turn being made in the hyperbolic shape. We see it in every one of our plays. It's ironic that there's been maybe some commentary out there that the declines have been exponential in the early life of a well. Well, guess what, it's like that in every shale play because you're draining fractures, and then the matrix kicks in and it turns the production. So any way -- anywhere we look at it on, for example, on Anderson 17, if you start plotting that, 0 at around month 6, you start to see the curves flatten pretty dramatically. And we've seen that all the way through all of those wells, including the Weyerhaeuser well, which is 13 months old now. We knew that going in. We were comfortable with that going in because there's a vertical well that's produced for 30-something years that has a 2.0 B factor. There's 3 short laterals that Encore Acquisition has drilled, that have been on since 2007 and 2008, that have anywhere from 1.4 to 1.6 B factors. It very well, it could be a 2-part curve here. We're kind of modeling initially a 1.3 B factor. With more wells and more history, we'll be able to refine that. But so far, we have a very nice type fit. As Gil said in response to Ryan's question earlier, we'll be able to provide that to you in our slide deck, which will be posted on our website beginning, likely, Monday morning.

Dan McSpirit - BMO Capital Markets U.S.

Got it. Very helpful. And as a follow-up here, is the risk profile different with the Ash wells, given that the laterals are being landed above the rubble zone?

Walter G. Goodrich

Yes, Dan. This is Gil. I would say that we have, all along, felt like the ideal landing spot would be down in the bottom 20 to 25 feet of the TMS. We talked today about the quartz content in the lower half of the TMS. So landing above the rubblized zone would put you still within that range, but you'd be in the upper part of that range. I'd say we're anxious to see the Ash wells completed. We hope, or are confident that that's going to not be an issue. But we certainly would rather see that before we start making any definitive wholesale changes in our landing target across the play. It is about 50 to 55 feet off the bottom, so it's not dramatically different from the lower landing target at 25 feet off bottom, and certainly, we'll still be in the lower half of the overall TMS. So as we look at life of seismic work that's been done, we're seeing stimulation indications far broader than that kind of footage difference. So I think we're highly confident, but until it's done, we actually have some flowback results. I think we'll just wait and see.

Operator

;

Your next question comes from the line of Brian Lively with Tudor, Pickering, Holt.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Just more questions on the TMS. As we've -- from the outside looking in, there have been -- I would say, there is some conflicting data coming from various operators in the TMS. Rob, I really appreciate all the comments, very compelling from that standpoint. If you guys were to boil it down, though, what do you think the fundamental differences are between the various perspectives here? I know you won't comment on the competency of other companies, but what are you -- how are you guys seeing the picture different? Is it cost-related? Is it this matrix contribution issue? Is it variability? Or just what is it?

Robert C. Turnham

Yes. Brian, one of the -- another slide or certainly commentary we're going to start discussing on Monday is lateral lengths, frac intervals, frac stage length and amount of proppant pumped, and we see a direct correlation, as Gil said, with proppant pumped per stage to results. So far it's been, I would say, somewhat linear. But no question, if you drill a short lateral with small amount of proppant pumped, the well is not going to do very well. And we think that's certainly has been performed in several wells. Several of the earlier wells were under-stimulated. And we think it's important that you give it the best shot by pumping, certainly, higher amounts of proppant. Where you land the lateral, as Gil said, and I think I said in my previous -- in my prepared remarks, we're seeing high quartz content, almost sand and silkstone-like in the lower half of the TMS. If you land above that, very well could be problematic in getting your frac off and stimulating appropriately. We're certainly seeing very good results by landing in the lower 25% or so of that formation. Those are the 2 things that jump out to us. Now whether there's geographic or geologic differences as you head south, that's a point that we'll have to just study and try to determine, as you get deeper, as you get more thermally mature and less productive. We just don't know the answer to that yet, but certainly hope to figure that out as well.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And as a follow-up to that, the GOR seemed pretty low upfront. Are you guys seeing an increase in GOR over time? It's good to have oil, but it's as good to have a drive mechanism.

Walter G. Goodrich

Yes, Brian, this is Gil. We're seeing very little change in GOR over time, in any of the wells that have produced thus far. A little bit interesting at Crosby because slightly higher GOR than we've seen in the other wells. It doesn't necessarily make a whole lot of sense to us in that we're essentially on strike with the Anderson wells. So no other region that we'd have a slightly higher GOR. I would just say that, as Rob said, we're not pounding the table on any one particular type curve, what you'll see from us on Monday of next week, is 3 different type curves ranging from a low of 400,000 to a high of 800,000. And we're doing that based on the data that we've seen and we've finally, now, at over a year with the first grassroots lateral being sufficiently online production, getting to a comfort level that we think it makes sense to put it out and start to talk about it. What others are saying, we're -- they're absolutely entitled to their opinion, and we're very comfortable with saying what we say, when we say it, how we say it, because that's what we believe, and we'll see how the play turns out a year from now.

Operator

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

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

If I heard you right, I think you had said that for the Smith well, you were planning on landing the lateral above the rubble zone. Is that, in fact, the case? And -- or do you plan on waiting to see results from the Ash wells before you make a decision on how you're going to drill that well?

Walter G. Goodrich

Yes, Mike, this is Gil. I would say, probably both. We currently we plan to land above the rubble zone, but in the case that we see something negative from either of the Ash wells, we might reconsider that. But right now, we would be planning to land just above that rubblized zone.

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

Okay. So without the liner, and a little bit different completion than what you did on the Crosby?

Walter G. Goodrich

Well, the liner part would be correct. Yes, we would not plan to run a liner. And frankly, even if we were to move and go back to the lower target, we would be drilling a slightly bigger hole with a liner contingent plan, but not definitively planning to run a liner unless we felt we had to during the course of drilling the well.

Operator

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

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

A couple of questions I don't think have been touched on yet. Should you get to a jade point of monetizing the TMS with -- through a JV. Would you be looking more for -- what would be your preference there? Would it be more a drill and carry or a large portion cash to pay down debt immediately or similar, outright sale of some acreage? What would be your preference at this point?

Walter G. Goodrich

Yes. Richard, this is Gil. I would say this, our strategy, as we tried to outline in our comments is, we're going to maintain adequate and ample liquidity under our revolver, and we're going to take steps to address the convertible notes during the course of this year. So I think that leaves us with pretty good flexibility to let the opportunities come to us in the TMS, and we're not going to try to force anything or push anything that doesn't make sense for our shareholders. We'll continue on with our development, and so we're a bit indifferent to exactly how it might come. We're not so indifferent as to what the value might be of the acreage. And unless we feel like we're getting sufficient value that can allow us to accelerate and therefore create incremental value, we won't be takers of anything. Cash and carry probably feels the best, call it 50-50-50, but if someone came to us with the right valuation, we would certainly consider a higher carry percentage. We are all-in to develop this asset, and really indifferent as to exactly how that occurs.

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

Okay. I know there's a couple of packages on the block right now in the TMS. What are you hearing on current environment for M&A activity there?

Walter G. Goodrich

Yes, well, clearly, there is some acreage on the environment. Exactly how that acreage stacks up with ours is a bit of a question, and we'll just have to see how that process goes through the marketing process. And as I said, we're not going to try to jam ourselves into the middle of something. We're happy to continue to be patient and develop our block.

Operator

Your next question comes from the line of Curt Freeman [ph] with Simons [ph].

Unknown Analyst

Turning focus a little bit to the Pearsall. It sounds like that well that was initially supposed to be spud in Q1 is going to be delayed and possibly not spud this year. Is that correct? And any color you can provide there would be helpful.

Robert C. Turnham

Yes, this is Rob. Well, I think the Crosby result, obviously, has us pretty excited and accelerating the spud date on the Smith well. And when we budget quarterly, we're obviously looking to spend as little money as possible in the early first half of this year, while we prove up the TMS. And that's really the driving force behind that shift. Now as we said in our prepared remarks, it's still on the schedule for later this year. We're monitoring production, a little more time watching the production doesn't hurt us on the Pearsall in that it's just a very new play. So it's kind of a combination of lack of wanting to spend the extra capital in the Pearsall at a time where we're accelerating the spud date on the Smith well.

Unknown Analyst

Yes. Okay, that makes sense. And then as a follow-up, turning to your Eagle Ford asset, it sounds like you all are aiming at some lower lateral lengths, about 6,000 feet now, which kind of leans towards the lower end of the prior range. Should that continue or should that move downward continue into the future? And then in addition to that, should we expect any upcoming well results from the Eagle Ford in the near-term future?

Walter G. Goodrich

Well, we're -- the 6,000-foot laterals were mainly geographic constraints. We're on a -- as you know, we're pad drilling on there and we have kind of an irregular shape right now that -- of our acreage where we're pad drilling, that's limited a certain number of these wells to 6,000 feet. Although we just did drill, call it, 3 -- 9,000, on average, 9,000-foot laterals. So it just varies, but the 10 days to TD is roughly -- in fact, we drilled 1 9,000-foot lateral in 9 days. So it just varies. But the last several wells have ranged anywhere from 6,000- to 9,000-foot laterals. We are -- we probably have 50 wells down there now, so we're not going to continue to show IP rates and things. That's in a development mode now. So no need to continue to do that. We will on the TMS because it's early. And we've done that in every one of our plays. Until we have a good feel for the results in that area, we're going to continue to press release those. But we're past that point in the Eagle Ford.

Operator

Your next question comes from the line of Joe Magner with Macquarie Capital.

Joseph Patrick Magner - Macquarie Research

Just curious if you all anticipate any changes to your borrowing base, given the change of reserves year-over-year and the shift in the makeup of the reserve mix?

Walter G. Goodrich

Yes, Joe, this is Gil. I think I gave pretty good color on that in the prepared remarks. The current borrowing base is still $210 million, that we are, we'll in the process of delivering our year-end reserves and report to our bank group, and then we expect a new borrowing base roughly, shortly after the end of the first quarter.

Joseph Patrick Magner - Macquarie Research

Okay, and just to clarify, there was a comment about returning to the area where the Denkmann well was drilled. Has that well been abandoned? Or do you still plan to continue remediation efforts, or reenter that well and drill sidetrack?

Walter G. Goodrich

Yes, the well has not been abandoned, and we are evaluating the best way to go about redeveloping that acreage using that wellbore. If that's what makes the most sense. We have not finalized our study at this point.

Operator

At this time, I have no further questions. I would now like to turn the call over to Mr. Goodrich for closing remarks.

Walter G. Goodrich

Thank you, Kim. And thanks, everyone, for your participation this morning. As you can see, we're very encouraged by the results of the Crosby and the overall TMS play, and we look forward to additional development in data points and we'll share those with you as they come in. Thank you.

Operator

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Good day.

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