Goodrich Petroleum's CEO Discusses Q2 2012 Results - Earnings Call Transcript

| About: Goodrich Petroleum (GDPM)

Goodrich Petroleum Corp. (GDP) Q2 2012 Earnings Call August 7, 2012 11:00 AM ET

Executives

Walter G. “Gil” Goodrich – Vice Chairman and Chief Executive Officer

Patrick E. Malloy III – Chairman

Robert C. Turnham, Jr. – President and Chief Operating Officer

Mark E. Ferchau – Executive Vice President

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

Analyst

Ronald E. Mills – Johnson Rice & Company, LLC.

Ryan Todd – Deutsche Bank Securities

Mike Kelly – Global Hunter Securities, LLC

William Butler – Stephens Inc.

Chad Mabry – KLR Group, LLC

Subash Chandra – Jefferies & Company

Pearce W. Hammond – Simmons & Company International

Cameron Horwitz – U.S. Capital Advisors LLC

Kyle Rhodes – RBC Capital Markets, LLC

Dan McSpirit – BMO Capital Markets

Richard M. Tullis – Capital One Southcoast, Inc.,

Michael Hall – Robert W. Baird & Co.

Operator

Good day, ladies and gentlemen, and welcome to the Quarter Two, 2012 Goodrich Petroleum Corporation’s Earnings Conference. My name is Emily, and I’m your operator for today. At this time, all participants are in a listen-only mode. We will conduct a question-and-answer session towards the end of this conference. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes.

I would now like to hand the call over to Mr. Gil Goodrich, Vice Chairman and Chief Executive Officer. Please proceed.

Walter G. “Gil” Goodrich

Thank you, Emily. Good morning, everyone. Welcome to our second quarter earnings call. I’d like to begin with introductions of the management team with us, first, with Mr. Pat Malloy, the company’s Chairman of the Board; Rob Turnham, President and Chief Operating Officer; Mark Ferchau, our Executive Vice President and Director of Engineering and Operations; and Jan Schott, Senior Vice President and Chief Financial Officer.

As is our standard practice, we’d like to remind everyone that comments that we may make and answers we may give during this teleconference conference call. Maybe considered forward-looking statements, which involve risks and uncertainties and we’ve detailed those for you in our SEC filings.

Approximately two years ago, with the acquisition of our Eagle Ford Shale position, we began a long-term strategic transition from a company whose reserves and production were 98% natural gas and 2% liquids, to a company’s assets, production, and reserves are more balanced between crude oil and natural gas.

While this transition has not always been as seamless and as quick as we may have desired, we are very pleased with the progress we have made. Crude oil, as a percentage of production on an Mcfe basis, has risen to just over 18% of production in the second quarter, and we are projecting will increase further in the fourth quarter of this year to approximately 23% of production.

Third quarter oil volumes will continue to grow and we’ve averaged approximately 3,500 barrels a day since the end of the second quarter. Due to the timing of the completion of five gross Eagle Ford Shale wells on two separate pads in September, we are projecting another meaningful increase in production as we enter the fourth quarter of this year.

Further, with a desire to both accelerate the early-stage delineation of the Tuscaloosa Marine Shale play and maintain financial discipline during this period by maintaining a $250 million CapEx budget, we expect some incremental volume impact associated with the transition of one rig from the south Texas area to the Tuscaloosa Marine Shale.

However, we continue to maintain our forecasted 2012 exit rate of approximately 5,000 barrels of oil per day. With continued success in the TMS, plus the non-core asset sale we announced last night. We believe we are very well positioned to run it multiple rigs in both the Eagle Ford Shale and TMS in 2013.

Our transition will continue, and we are confident further progress will be made over the coming quarters, as we will direct virtually all of our drilling and development capital expenditures to oil-directed drilling in both the Eagle Ford Shale and the Tuscaloosa Marine Shale. In the TMS, we significantly expanded our footprint and acreage position in the thick, high-resistivity portion of the play during the second quarter.

We exited the first quarter with approximately 102,000 net acres. We updated that position on May 23 to reflect the addition of 18,000 net acres, and we subsequently added another 12,000 net acres, during the second quarter, to bring our total net position to 132,000 net acres.

The agreements we have in place and the wells we have participated in, to date, provide us excellent insight into the development of the play, and we are pleased and encouraged by the early-stage well performance in the TMS.

As a result, we are increasing our capital allocation to the TMS during the second quarter of this year, with plans for further acceleration in 2013. At the core of our natural-gas-to-oil strategy is the rapid expansion of revenues, cash margins, and cash flow.

Our growing crude oil volumes, coupled with our excellent hedge position, are achieving the projected results. While production, measured on an Mcfe basis, declined by approximately 6% sequentially. Discretionary cash flow, led by sequential oil volume growth, grew by 16% over the first quarter of this year.

Both EBITDAX and cash flow grew to record levels as realized pricing, after giving effect to our realized crude oil and natural gas hedges, increased by 34% over the year-ago period to $7.58 per Mcfe.

Going forward, we have an outstanding hedge position to protect against price volatility during the second half of this year. We have recently added to our crude oil positions and, coupled with our natural gas hedges; provide us price protection on approximately 90% of our anticipated production in the second half of this year, at a blended average price of approximately $8.60 per Mcfe or $52 per BOE.

Turning to liquidity, we exited the second quarter with $158 million drawn on our senior credit facility, with a borrowing base of $265 million giving us unused borrowings plus cash on hand of approximately $109 million. In addition, we will deliver our mid-year reserve for a track block bank group in the near future, and expect to have a revised volume base near the end of the third quarter.

Finally, we are pleased to announce the execution of a Letter of Intent to sell our South Henderson assets for $95 million. This transaction, which is expected to close by the end of the third quarter, will further enhance our liquidity, allow us to efficiently redeploy capital from natural gas assets through the numerous oil development opportunities, in particular the early stage development of the TMS, which we are very fortunate to have in our inventory.

And with that, I would like to turn the call over to Rob Turnham.

Robert C. Turnham, Jr.

Thanks, Gil. Just to follow up on the South Henderson sale and East Texas for $95 million, we have an effective date of July 1 and an anticipated closing date of October 1. We expect definitive agreements in place in the near term. The sale of this non-core Cotton Valley asset will plug the hole in our CapEx budget for 2012 and provide additional liquidity in 2013.

We will discuss in more detail the metrics around the transaction after we close, but as you will see in our management presentation and public filings, the South Henderson field has a small acreage footprint for us, compared to our remaining Cotton Valley, Haynesville, Eagle Ford, and Tuscaloosa acreage positions.

The sale of this field will provide substantial incremental capital that will allow us to continue to develop the Eagle Ford with two rigs running until late this year, and accelerate de-risking of the Tuscaloosa, which will unlock tremendous value in financing options going forward.

Focusing on results for the quarter, production was 8.3 Bcf equivalents, with liquids comprising 27% of the total and 71% of revenues. Oil volumes grew by 17% sequentially, to 2,800 barrels per day, or 18% of total production.

NGL volumes for the quarter averaged 1,300 barrels per day. Since the end of the quarter, we’ve averaged 3,500 barrels per day as we’ve added 4 gross, 3 net, wells to production, with 5 gross, 3.5 net well completions set for September.

Third-quarter guidance is again being affected by completion timing from pad drilled wells, with the 5 wells being completed in the September providing very little benefit to production for the quarter. That said, this obviously sets us up for a higher sequential oil volume growth rate in the fourth quarter as we continue to target the 5,000 barrel per day exit rate.

We currently have two rigs running in the Eagle Ford and are now on pace to drill and complete 27 gross, 19 net, wells in the trend for the year, which is 5 gross, 3 net, fewer wells completed than previously anticipated.

Capital expenditures for the quarter totaled $74.3 million of which $39 million was spent on drilling and completion, $13.6 million on leasehold acquisitions, $1.5 million on facility costs, and $0.2 million on miscellaneous expenditures. For the quarter, we spent 73% of our capital in the Eagle Ford, where we had two to three rigs running, and 24% in the Tuscaloosa, with a combination of leasehold acquisitions, and drilling and completion expenditures associated with the two non-operated wells and one operated well.

Capital expenditures for the six months totaled $135.7 billion with a $115.1 million on drilling and completion costs, $18 million on leasehold acquisitions, $2.4 million on facility costs, and $200,000 on other miscellaneous expenditures.

Second half capital expenditures are forecasted to be $115 million, bringing the estimated total for the year to approximately $230 million, which was the low end of previous guidance. We expect to run two rigs in the Eagle Ford until later this year when a portion of our pad drilling is completed, then one rig until the end of the year, with the potential to add a rig back to the area in 2013.

We anticipate moving a second rig to the TMS later this year, which we will accelerate the de-risking of the play. We continue to hold all of our natural gas acreage and 7 Tcf of resource potential, with very little CapEx for the year associated with gas directed activities. All of our North Louisiana acreage and East Texas acreage is held by production, with the exception of our Angelina River Trend, where we have negotiated an extension of our leases through 2013.

By virtue of this extension, we have further cut almost $10 million out of our gas directed CapEx for 2012, and now have the ability to allocate 100% of our 2013 capital expenditures to oil plays, if we choose to do so.

In the Eagle Ford Shale trend, we conducted drilling operations on 13 gross, 9 net wells, added 7 gross, 4.5 wells net wells to production for the quarter, as I said which was one less than anticipated due to the completion timing.

In addition to the Eagle Ford, and our secondary target in the area, the Buda Lime, we are monitoring a Pearsall shale well drilled, offsetting our acreage where we have approximately 10,000 net acres prospected for potential development.

In the Tuscaloosa Marine Shale trend, we are drilling our first operated well, the Denkmann 33 H-1, and participating for a non-operated interest in the Joe Jackson 4H-2 well, both of which are expected to be completed within 30 days.

We will move our operated rig and set the Crosby 12H-1 well in Wilkinson County after the Denkmann well is completed. We had filed permits on two additional operated wells, the Huff and Smith wells, which are to be spud later this year, with more to follow. We will be participating in at least two additional non-operated wells, the Ash 31 H-1 and 31 H-2 wells, for a 20% interest in each, one of which we expect to spud in the third quarter.

In closing, the sale of South Henderson will provide us with liquidity through 2012 and into 2013, which will allow us to drill and complete several additional TMS wells on our 132,000-acre block and, equally important, establish decline curves and optimum completions, which will lead to higher valuations for the play. With continued success, we expect to be able to finance or bring in a joint-venture partner at attractive terms that will allow us to accelerate development in 2013.

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 $41.3 million. For the second quarter, if you include the realized gains on derivatives of $21.3 million with our reported revenue, adjusted revenue was $62.7 million, an increase of $3.9 million, or 7%, over the adjusted revenue for the comparable period last year of $58.8 million, and $1.5 million, or 2%, over the adjusted revenue for last quarter of $61.2 million.

Our second quarter average realized prices, excluding the impact of realized gains on derivatives, were 98.96 per barrel for oil and $2.41 per Mcf for gas. If you include the impact of the realized gains on derivatives, the average sales prices were $107.15 per barrel for oil and $5.26 per Mcf for gas this quarter.

This represents an $8.19 per barrel uplift in the price for oil and a $2.85 for Mcf uplift in the price for natural gas. Through our continued use of strategic derivatives to lock in prices and with the additional benefit of increasing oil production and processing of NGL, we would expect this trend to continue.

As Gil mentioned, in late July we added an oil swap for 500 barrels of oil per day at a price of $92.20 for August 2012 through December 2013. Our plan is to continue to layer on additional oil derivatives as we increase oil production during 2012. We also continue to watch natural gas for an opportunistic time to hedge portions of our 2013 production. Please see our website later today for an updated slide on our current derivative position.

Moving on to expenses, a predictable quarter on the cost side with all per unit costs coming within previously issued guidance. LOE this quarter hit the midpoint of guidance at $0.81 per Mcfe.

The second quarter included about $0.08 for workovers. If you exclude workover costs, our LOE rates would have been $0.73 for the second quarter. The LOE rate was $0.88 for the first half of 2012, and if you exclude $0.17 for workover activity, the LOE rate would have been $0.71. As we have stated before, as we increase our oil production during 2012, we would expect our LOE rates to gradually increase during the year.

DD&A was $4.17 per Mcfe for the quarter, compared to $3.68 last quarter and $3 per Mcfe for the prior year quarter. The DD&A rate for the first half of 2012 was $3.92 per Mcfe, which was with in guidance given earlier this year of $3.75 to $4 per Mcfe. We will reset our DD&A rates for the second half of 2012 upon receipt of our mid-year reserve report.

G&A costs came in at $0.81 per Mcfe this quarter, in line with guidance and below last quarter's rate of $0.90. About $0.18 or 22% represent non-cash stock-based compensations. There were no impairments reported in the second quarter.

As Gil mentioned earlier, as of the end of the quarter we had $158 million drawn on our senior credit facility. Our current borrowing base is $265 million, thus we ended the quarter with $2 million in cash and an undrawn borrowing base of $107 million, for a total of $109 million.

The next redetermination of our borrowing base will occur in September, in conjunction with our mid-year reserve report. We have included reconciliations on the last pages of our press release for all non-GAAP measures to the closest GAAP measure. Please refer to these reconciliations for more detail. We plan to file our second quarter 2012 10-Q with the SEC this week. Please see our 10-Q for a more detailed financial discussion.

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

Walter G. "Gil" Goodrich

Thank you, Jan. As Rob highlighted, the closing of the announced divestiture of South Henderson field later this quarter will provide us a meaningful boost to our liquidity and go a long way toward providing the incremental funding to – with our cash flow from operations, to fund aggressive oil directed program in 2013. And, we are extremely excited about the growth we believe we can achieve for our shareholders over the coming quarters.

And with that, Emily, I'll turn it back over to you for questions.

Question-and-Answer Session

Operator

Thank you, Gil. (Operator Instructions) Please stand by for your first question. Okay, your first question comes from the line of the Ron Mills with Johnson Rice. Ron please go ahead you’re live in the call:

Ronald E. Mills – Johnson Rice & Company, LLC.

Good morning guys. Question a couple of questions on the TMS. Rob, in terms of the Denkmann, where are you in that well in terms of in drilling in the lateral? When do you think it will reach TD? It sounds like you think it will be completed late August, early September, but just curious in terms of the timeframe on drilling?

Robert C. Turnham, Jr.

Yeah, we're out in the lateral. We tend to not give the play-by-plays everyday as to where we exactly are, but certainly expect to be at total depth and have the well fracked within the 30 days that we've mentioned. So, optimistic that we'll continue to make progress there and hit our targets.

Ronald E. Mills – Johnson Rice & Company, LLC.

Okay. And then the TMS well cost, there's been a lot of questions about that. I think you've talked in the past about $13 million, $14 million. And is that where you've – where you're expecting costs to come in on, now that you're most of the way through your first well, and as you are looking to spud your second in the next month?

Robert C. Turnham, Jr.

Well, our AFE is $13 million. It's out there in the public consumption when we proposed the wells through utilization. Obviously, this well is taking a little bit longer, but it all depends on how many days we get down once we hit total depth. So, a little too early to kind of say what’s going to be. It's certainly incrementally, at this point, not material, but we'll have to kind of give you a play-by-play of that at the end of the process.

We've seen additional proposals come into the door also, which are a good bit lower than previous whisper talk on completed well cost, so we still feel comfortable with the $13 million AFEs that’s exactly what our second well AFE is well, our Smith and Huff wells that are coming out. We are going to do a little science on the Crosby well, take a core in that well. But we're also seeing other operators put AFE similar in cost. And then, of course, with time, as we develop optimum drilling and completion practices and get lower service costs on the completion side, we expect those costs to continue to trend down.

Ronald E. Mills – Johnson Rice & Company, LLC.

Great, and then is it fair to assume for your comments, that if you look at today's plan for next year, you would plan to have two to three rigs in the TMS and one to two rigs in the Eagle Ford? And I guess what I'm driving at the South Henderson sale give you a lot of liquidity for this year and heading into next year, and obviously a TMS JV would drive that level of activity in the TMS. Just looking at the liquidity and on expected well costs that would point to a little bit higher CapEx level this year. How does that fit into your liquidity, especially with those convertible notes becoming putable?

Walter G. "Gil" Goodrich

Yes well, Ron, this is Gil. The convertible notes don’t become putable until October of 2014, not 2013, so another year out before they become putable,0 or callable, for that matter.

Ronald E. Mills – Johnson Rice & Company, LLC.

Okay, good.

Walter G. "Gil" Goodrich

I think that what you've outlined is fairly consistent. We obviously have not formally proposed a budget to our Board for 2013, but the closing of the South Henderson sale plus some incremental delineation of the TMS in the second half this year, is certainly geared towards putting us in position to be able to run a couple of rigs in the South Texas Eagle Ford field and two, perhaps even three rigs, in the TMS.

Ronald E. Mills – Johnson Rice & Company, LLC.

Okay, great. Thank you, guys.

Operator

Thank you for your question. Your next question comes from the line of Ryan Todd with Deutsche Bank. Ryan, please go ahead. Your line is in queue.

Ryan Todd – Deutsche Bank Securities

Great, thanks. If I could just follow-up from a liquidity point of view, are you confident at this point, that you're sufficiently capitalized post the asset sale to carry yourselves from here through a potential TMS JV or sale without having to do anything else?

Walter G. "Gil" Goodrich

Yeah Ryan, this is Gil. We are very comfortable, particularly in the fact that as oil volumes continue to grow, both in 3Q and 4Q and maintaining that $250 million CapEx, you are going to see a significant narrowing of the CapEx to cash flow relationship as we go forward. And so, that's going to provide us, in addition to the liquidity from the South Henderson sale, a lots of flexibility in terms of exactly what the budget is for next year and we will let results in the field, commodity prices and our outlook exactly how aggressive we want to be dictate exactly where the CapEx is for 2013.

That being said, as Rob mentioned, if we can move the ball a little bit further down the road over the six months or so, and further de-risk the TMS, we certainly view that as a great opportunity for bringing in a partner of joint venture, which could further boost the liquidity of the company and accelerate TMS development. So that's all in the longer range plans. We still have a couple more steps between now and the end of year to get there.

Robert C. Turnham, Jr.

And Ryan, I might add, even with that going on, we'll still have East Texas Cotton Valley assets at Beckville, Minden. We still have plenty of other assets, if we choose to go down the route of selling those, and keeping all 132,000 acres in the TMS. Plenty of options. It would be a mistake to put all of the eggs, at to financing options, in the TMS, because there are plenty of quivers, barons in the quiver left for us to find who would love to develop.

Ryan Todd – Deutsche Bank Securities

Okay, thanks. And then in the Eagle Ford, I mean you continue to drop activity a little bit over the second half of this year. Is that purely a function of capital needs in the or at least the desire to accelerate in the TMS, and I mean what do you think is the right level of activity in the Eagle Ford on a go-forward basis? What would you like to be able to do there?

Walter G. “Gil” Goodrich

Ryan, this is Gil. As I said in my prepared remarks, it’s really a desire to accelerate the delineation of the TMS. We think that’s likely to be very excellent value creation for us over the next six months. And at the same time, we’re doing that to maintain the financial discipline by keeping the budget at $250 million. And since we’re already (inaudible) gas-directed CapEx, the only place really to do both of those things is to move the rig out of the TMS. So an answer to the second part of your question, ideally we’d love to be in a position to run two to three rigs in the Eagle Ford next year. But we’ve got to live within the reality of our balance sheet and how fast cash flow is growing. So I think it probably means, again we haven’t set a 2013 budget, but a couple rigs in South Texas, and two, perhaps three in the Eagle Ford, excuse me, in the TMS for next year. That’s what we’re trying to position the company to be able to do.

Ryan Todd – Deutsche Bank Securities

Okay, any color on the recent Eagle Ford well results in terms of what you’re seeing from a rates point of view?

Walter G. “Gil” Goodrich

I would just say that we continue to be very pleased with our Eagle Ford results. We’re into pad drilling and down spacing, and we have had some delays in production, because we want to protect existing producing wells as we’re fracking offset wells. That’s part of just what goes on in the field, particularly when you’re getting onto the pad drilling, but very, very pleased we’re really drilling on down spacing. So we’re not seeing any depreciable change in well performance. And maybe to get a half a step in front of our reserve engineers, which I always hate to do. We think there's at least potential for some incremental improvement in the overall EUR projections from our Eagle Ford wells here at mid year, at least that’s an internal point of view.

Ryan Todd – Deutsche Bank Securities

Great, I appreciate that. I’ll leave it there.

Walter G. “Gil” Goodrich

Thanks.

Operator

Thank you for your question Ryan. Your next question comes from the line of Mike Kelly for Global Hunter Securities. Mike, please go ahead. You’re live in the call.

Mike Kelly – Global Hunter Securities, LLC

Hey guys good morning. Thanks for taking my call. Somebody just give a little bit more color on the factors, just talking about the factors that led your decision that now is indeed the right time to put a second rig in the TMS versus really doing more science work with just rig here, now well and we’re still in the early innings here?

Walter G. “Gil” Goodrich

Yeah sure, this is Gil. Something we can’t talk about because, as I mentioned, we are under an agreement, that’s a data sharing agreement, and we’re not going to divulge that information. Having said that, the initial grass roots Weyerhaeuser will came online in November, late November of last year. So we are now getting out there to a point in time where we’re getting some lags and some maturity on the type curve from that well. We’ve seen a second well come on, which is the Horseshoe Hill well, which came on a month or so after that. We’ve now got a few months under our belt on some of the longer laterals. And a few months doesn’t completely make a type curve, we certainly understand that. We’re not in a position to start pounding the table on any particular EUR at this point. But we’re beginning to get the framework for a general range in which we would expect EURs to land, and as I said in my prepared remarks, we’re both pleased and encouraged by what we’re seeing so far.

Mike Kelly – Global Hunter Securities, LLC

Okay and maybe kind on that same topic there. And I’d asked you last quarter in the conference call addressed some of the larger knocks against the TMS, and we talked about clay content, well costs. You seem to have addressed those fairly well. I think one of the new knocks on the play has been the decline curves, and some folks, they think that after 30 days these things really fall off a cliff, and just hoping you could comment and what’s your, you’re seeing there if you can and just kind of general comments on that?

Walter G. “Gil” Goodrich

I would say that we, on the one hand understand where people might be saying that. On the other hand, we don’t agree with it. We’re dealing with a reservoir that for most of these wells is 11,000 to 12,000 feet below the ground. All of those wells have been flowing up about a 5.5 inch casing. You need time with oil wells, particularly wells like this that are as high in oil percentage as they are. With the lift mechanism to get those wells, both with tubing in well and on some sort artificial lift the gas lift or pump. We are starting, we believe to see that take place and we just, internally, are confident that’s going to have a profound impact on the ultimate curves. And I guess I would add one more comment, even with that, we still are pretty encouraged by the curves.

Robert C. Turnham, Jr.

Yeah Mike this is Rob. The Anderson wells, there’s been a third-party report on basically using the two oldest wells, which were short laterals flowing up casing with no tubing and no artificial lift, and then taking that short lateral decline curve and applying it to two long lateral, much better wells and coming up with conclusions, and that’s foolish, in our mind. It’s all about lateral length, it’s all about completion technology and how you flow the wells back in maximizing production, and artificial lifts. So it’s a big mistake, and to give you an idea, if you just flow a casing in an Eagle Ford well for seven months, guess what the decline curve is going to look a lot different also. So, it seems to us, a little irresponsible to jump out ahead of this, it’s early innings. We have yet to put the optimum completion technique but even with that we’re very pleased with the results we’re seeing.

Mike Kelly – Global Hunter Securities, LLC

Okay great then that’s good color. Just real quick the timing of the JV in the TMS, have you really started the process there? And what’s the ideal structure look like for you guys?

Robert C. Turnham, Jr.

We haven’t decided for sure whether we’re even going to JV this acreage. What we want to do is de-risk it by spreading wells out, putting the proper and the optimum completions on establish the type curves, create a much higher valuation, and then we’ll explore all of our options whether it’s financing under on a project basis, and we have plenty of interest in that already, or whether it’s bringing in a joint venture partner. We’ll reserve that decisions later, but by accelerating the development and bringing an extra rig in there it fast forwards, proving up the acreage, which is going to create the value much faster than had we just taken a much slower development of schedule on it.

Mike Kelly – Global Hunter Securities, LLC

Yeah, thank you.

Robert C. Turnham, Jr.

Thanks.

Operator

Thank you for your question Mike. Your next question comes from the line of William Butler with Stephens. William, please go ahead. You’re live in the call.

William Butler – Stephens Inc.

Good morning.

Robert C. Turnham, Jr.

Good mornings William.

William Butler – Stephens Inc.

Can you all comment on how many long laterals versus short laterals, you all are targeting right now in the Eagle Ford? Is it again just sort of a lease line dependent or have you found any conclusive results?

Robert C. Turnham, Jr.

Both. It is the better wells are longer laterals. We’re averaging, I think, if you look at our well count for the year, it’s going to about 7,200 foot average lateral lengths, but it does vary based on acreage configuration. No question, just like the Eagle Ford and the TMS is the same way. Longer laterals make better wells you dollars per linear foot goes down. You have more rock exposed to the well bore, and it creates better wells. So that’s our goal, and ideally we would drill all, call them 9,000 foot laterals in the Eagle Ford, but due to acreage configuration we’re somewhat limited.

William Butler – Stephens Inc.

And what about number of frac stages or frac spacing?

Robert C. Turnham, Jr.

We continue to tweak a little bit, but we typically spread our frac stages over 275 to 300 foot intervals.

William Butler – Stephens Inc.

Okay.

Robert C. Turnham, Jr.

And we pump, I call it £325,000 to £350,000 of profit, it kind of depends on the area, we call it £325,000 over that 300 foot interval.

William Butler – Stephens Inc.

So you’ve kind of that recipe is pretty well established now, it sounds like?

Robert C. Turnham, Jr.

Yes, we’re not altering it very much in the Eagle Ford. We like what we see. We feel like it’s the right recipe. Now, we may try a smaller frac job down the road, a little more slick water, a little less profit to see the benefits. We’ve seen other operators in the Eagle Ford trying that with some success. It’s obviously a cheaper version and a cheaper completion. And we’re going to be tempted try that in the future, but so far we’ve not, we’ve just stayed with our kind of traditional completion plan.

William Butler – Stephens Inc.

Can you all comment on well costs? Are those coming down? What would the average well cost be for sort of that average of 7,000?

Robert C. Turnham, Jr.

Yeah. Now, we're comfortable with the kind of $8 million, $8.5 million completed well cost that we have in our presentation. The cost savings obviously are two fold, the pad drilling allows you to skid the rig and the zipper fracs, you're using the equipment less time, and that's been beneficial.

William Butler – Stephens Inc.

And that has some longer laterals in it sort of, or is that all the shorter laterals?

Robert C. Turnham, Jr.

That's just, again, that average. The average is going to have mix. We're spending more money than that on longer laterals, obviously, but when you kind of mix in that, the $8 million, $8.5 million seems pretty close.

William Butler – Stephens Inc.

Okay. And there's been a lot of commentary recently on down spacing, potentially in the Eagle Ford. What are you all comfortable saying on that?

Robert C. Turnham, Jr.

Our wells are 660 feet apart where we have the tightest spacing, which based on our lateral length, equates to about 100-acre spacing. When we frac the wells, the offset wells see water. It affects the oil production. We shut those wells in when fracking. When we bring the wells back on it takes a little time for the oil to get back to where it was, but we do see that occurring, and therefore we don't see any – at this point, don't see any impact to EUR projections, but you do – as you're pumping the frac jobs, you do see the water extend out. It’s the equivalent of 80 acres spacing if you drill shorter laterals.

That doesn't mean that you can't come back in at a later date and downspace, maybe even with small frac jobs to capture some of the oil in between those wells. But we're just a long ways away from trying that. We are comfortable with the 660 between well bores at this point.

William Butler – Stephens Inc.

Okay. So then on your pads that you all are drilling; how many wells per pad are you all…

Robert C. Turnham, Jr.

We average three wells per pad is what we're, is the average.

William Butler – Stephens Inc.

Okay, great. I'll hop back in the queue. Thanks.

Robert C. Turnham, Jr.

Okay, thanks William.

Operator

Thank you for your question. Your next question comes from the line of Chad Mabry with KLR Group. Chad, please proceed. You are live in the call.

Chad Mabry – KLR Group, LLC

Thank you, good morning. Another question on the Tuscaloosa. Looking at the Encana's Anderson wells; could you help quantify how much your acreage position is kind of in and around those wells in Amite County?

Robert C. Turnham, Jr.

Yeah, in and around, I don't have the county breakdown in that particular region, breakdown. We probably have 55,000, 60,000 acres in Mississippi or in the northern portion of the play. And I would say an Amite County is probably equal to or greater than Wilkinson County. So I think it's a good portion of our Mississippi acreage is, at least, in that general area, but, I'm sorry, I don't have the breakout in that particular, specific area.

Chad Mabry – KLR Group, LLC

Okay. And just kind of given your participation in those wells, I mean would it be safe to say at this point that that acreage or that area is more or less de-risked at this point?

Robert C. Turnham, Jr.

From a geologic standpoint, we feel very good about a much bigger area than that. But again, what you want is more wells down with more production history, it with optimum completions to determine what that decline curve may look like. So certainly, between the Anderson wells and the Weyerhaeuser wells, I'm sure many of you may have seen, Devon I guess reported very good production results from their Weyerhaeuser well, even though the initial completion report was a good bit lower than their 20 or 30-day average, that’s a good area, no question about it, but we think, we don't see any reason to condemn any of the acreage yet. We just need more wells spread out with more history.

Chad Mabry – KLR Group, LLC

Okay. That’s helpful. And then just a quick follow-up on the Pearsall. Any kind of near-term plans to pursue that formation or is it just kind of wait and see what the Pals Ranch looks like?

Robert C. Turnham, Jr.

It's wait and see. Clearly, we're intrigued by it, but way too early, and there is very limited information in the market. So, that well being adjacent to our block will be interesting to monitor. Hopefully it comes in, in a big way, and then we'll consider development, and maybe switching up Eagle Ford well down the road to test it, but way too early to make those calls.

Chad Mabry – KLR Group, LLC

That’s helpful. Thanks guys.

Operator

Thank you for your question. Your next question comes from the line of Subash Chandra with Jefferies. Subash, please go ahead. You are live in the call.

Subash Chandra – Jefferies & Company

Yeah, thanks. Can you have a sort of an updated view on, what do you think you want to see from the Denkmann well, whether it’s a 24-hour, seven day rate or 30 day rate?

Walter G. “Gil” Goodrich

Yes, Subash, this is Gil. We really, yeah, I think both are important to us. I think both are meaningful. As Encana has done with the Anderson wells, in fact all of their wells, we think the 30-day rate is probably a better measure, and we would plan to probably put out both a 24-hour rate, as well as a 30-day rate.

Subash Chandra – Jefferies & Company

Do you have a number in mind that you think you would like to see adjusted for choke sizes and bottom well pressures?

Walter G. “Gil” Goodrich

Yeah, I mean that is a little bit of a slippery slope, because there's a lot of moving parts, lot of variables. It depends on how many feet you get out there, how long the lateral ultimately is. But I think something similar to what we saw from the Anderson wells, let's assume that you get out 7,000 to 8,000 feet of lateral length on a 14/64- to 16/64-inch choke, somewhere in that range. We would expect to see well in pressures between 2,500 to 3,000 pounds, maybe not quite 3,000 on that kind of choke and see rates 700 to 1,000 barrels a day, somewhat in that range.

Subash Chandra - Jefferies & Company

Got it, thank you. Very helpful. And have you updated your TMS spending this quarter? I might be stale on this, but I had somewhere $20 million to $45 million for the year, but has that number changed as a result of that rig movement?

Robert C. Turnham, Jr.

Yeah, this is Rob, Subash. Yeah, it has, we’ve reallocated some capital to the TMS. I think we are going to put $25 million of additional capital in the TMS and moved it, no, I'm sorry, $20 million into the TMS as we reduced down by $25 million or so from the Angelina River Trend, and then fewer wells on the Eagle Ford. So $20 million to $25 million of additional capital by year end. It’s going to basically come from four gross additional TMS wells than what was originally evolved. We had four gross, two net wells originally and I think now we are eight gross and four net TMS wells that are planned for. Now, not all of us are going to get completed probably 1.5 to 2 of those will not get completed until early 2013, but we're going to be drilling those wells in 2012.

Subash Chandra - Jefferies & Company

Okay. And I assume that the 5,000 barrel per day Q4 number exit rate does not include TMS?

Robert C. Turnham, Jr.

It includes some risk volumes for the wells that we expect to be online. But what we've done is we've taken kind of a risk to Eagle Ford curve and used that as our projected TMS. But obviously, because of the timing of the completions and the interest in the well on average being somewhat lower it’s not a huge impact to 2012 volume estimates.

Subash Chandra - Jefferies & Company

Okay. In the Encana wells that you're seeing, are you seeing a trend towards lower AFEs and say on a per-foot adjusted basis, or however you might want to normalize the wells?

Robert C. Turnham, Jr.

Yes, absolutely. And we'll let Encana talk about their wells, but we expect them to be down in the same range that we are on future wells. And I think as they’ve described and we can’t complain, they've done a lot of science on these early wells, and we are confident that they are going to drill them in similar CapEx range to what we're drilling.

Subash Chandra - Jefferies & Company

Okay. And one final one, I guess based on a lot of the questions you heard today and prior questions on TMS, what would you highlight as sort of the more significant myths about the play that you think you can rebut with some data having seeing the wells you’re seeing?

Walter G. “Gil” Goodrich

Yes, Subash this Gil. I think on performance, as we've talked about in the past, decline curves obviously get better with time, and we’re still very early in that process. We are seven, eight months out on the first grass roots well, and while that’s a pretty good indication, it's not, as I said earlier, something you’re going to go absolutely pound the table about. We do think, however, it's starting to frame up, in a pretty good sense. The range is in which we would expect EURs to land and we’re drawing from, certainly the Eagle Ford in that, but other shale plays as well, in terms of just hyperbolic curve shape, feed factors, those kind of things. So we’re not pounding the table on any one EUR, we think the range projected results through that first seven months or so is encouraging.

And I think as much as anything else, we in the industry have seen some issues with the drilling, the drilling of the lateral and at least in my mind, we’re moving from a reservoir clay content EUR risk-type as being the primary concern for the play to, at least in my mind, it’s the drilling, if the drilling procedures and techniques which need to be refined and fine tuned in order to get costs at the optimum level. And that frankly is a far better proposition for us to be facing than one in which the reservoir just won’t perform. So that’s our take and time will prove out how that ends up.

Subash Chandra - Jefferies & Company

And in that reservoir comment, I guess you would just sort of include the need, or the lack of need, for natural fracturing and lateral placement and so how well figured out are those two elements?

Walter G. “Gil” Goodrich

Yeah, that's another misconception, we think, Subash, that everybody walks around talking about clay content as an issue that’s a major issue. It’s not uniform across the entire interval backward landing our laterals in the bottom 25, 30 feet, where it’s much more like layer cake and fractured. And that’s obviously beneficial, it’s not ductile, it’s perhaps some have thought the fuller. But we feel like we are in the right area in fact we think everyone is active right now at least in a better reported results are now landing in the same integral. And we can tell you that it’s acting very fractured as we see on the course.

Robert C. Turnham, Jr.

Gil, let me add just one comment for that is, across the play, what you will see, almost routinely, is an increasing resistivity profile through the TMS as you go from top to bottom . And we believe, at least internally at Goodrich that, that’s being driven by mineralogy and rock characteristics, and the better quality and better rock is laying down in the bottom section, so that your are seeing higher clay content in the top, you're seeing more calcium carbonate, more quartz down that bottom which is, give some incremental quality improvement, which is driving resistivity higher, which is allowing resistivity to better read the oil saturation in the reservoir. Hence, we think landing in the bottom is not only landing in the better part of the quality of the rock, but it then is allowing you to stimulate the vast majority of your frac going up the entire section and end up with better wells results.

Subash Chandra – Jefferies & Company

And one final one,. I’ll get back in the queue. Is that your understanding, sort of an adjustment that Devon might have made, and I guess landing in the bottom part, there is no risk of limited frac barrier no frac barrier?

Robert C. Turnham, Jr.

Yeah, I certainly don’t want to make statements for Devon Energy, they speak for themselves. I believe they did on their most recent call, acknowledge that they had moved their landing lateral position down into section from their prior wells. And so hypothetically, if you would land one up in the upper part of the TMS, at least in our view, and you have got 70% to 80% of your frac going upwards by natural gradient, then hypothetically, it’s likely you could have landed up in the top and stimulated something up above the top of the TMS, which would be a ductile shale and not provide very encouraging results. So we, at least here at Goodrich, we think moving down in the lower part landing, as Rob said, 20 to 25 feet off the bottom of the TMS section is optimal. And it allows us to fully stimulate the zone by landing in the very best part.

Subash Chandra – Jefferies & Company

Great, thank you.

Robert C. Turnham, Jr.

Thanks.

Operator

Thank you for your question. Your next question comes from the line of Pearce Hammond from Simmons. Pearce, please go ahead. You are live in the call.

Pearce W. Hammond – Simmons & Company International

Good morning guys.

Walter G. "Gil" Goodrich

Hi Pearce.

Pearce W. Hammond – Simmons & Company International

Gil, I would love to get your perspective on the gas macro, especially since you guys have a good and unique look into Haynesville. Obviously, gas prices have come up here recently, so any updated thoughts on the macro?

Walter G. "Gil" Goodrich

Pearce, it’s funny you should ask, yesterday you shall receive, funny you should ask, and I’m digging through my file. I took at a look at the big shale gas plays updated, the Marcellus, the Barnett, the Woodford, the Fayetteville, and the Haynesville actually, I threw the Piceance in, which is predominantly gas. Collectively and this is not all from one particular snapshot in time. But collectively those six gas dominant plays are down almost 500 rigs from their peak, led by the Haynesville which is down into the 30 rigs running from a peak of about 185.

So we’re down at really, really important levels, I think time is important. Rome wasn’t built in a day growing volumes, and it won’t be built in a day shrinking the volumes. But clearly in our view, with gas rigs in the big plays, and even the Marcellus is down by almost 50 rigs from its peak which we think is extremely important. Barnett is down by about 140 rigs, Woodford is down by about 40 rigs. The Fayetteville is down by a little over 30 rigs and the Haynesville is down by about 150 rigs.

We think that time is our friend and we don’t know if that’s end of this year or sometime in 2013 or going into 2014 but I can tell you that we are certainly pleased and ready with our large footprint of Haynesville acreage that at the point it starts to challenge our oil-directed activity for capital will be, we’ll be shifting capital that way. And as Rob said, we’re blessed with one particular agreement in place, and then the rest of our gas acreage being RAH/BP, we’ve got great flexibility to spend almost no gas capital next year unless we choose too. So we think we’re going in the right direction peers.

Pearce Hammond – Simmons & Company International

Thank you for that color. And then, I know it’s early, but what counties do you believe represent the core of the TMS?

Walter G. "Gil" Goodrich

Well I think we’ve to start from where the activity has been, and clearly a mid county in Mississippi is leading the activity. The Horseshoe Hill well that Encana had drilled often kind of central-southern Wilkinson County of Mississippi, just to the west, has to be in that. We think the northern tier of East Feliciana, West Feliciana, Tangipahoa, St Helena, and Washington, Parishes Louisiana, just south of the Mississippi border, are clearly in the play. And from a geologic perspective, as Rob alluded to, we see it as somewhat broader than that.

That we think as you move west across the Mississippi River into Louisiana, Southern Concordia, Avoyelles, where EOG is drilling their first well, has permitted a second well, is into play. We believe that the western part of Avoyelles will start to see the resistivity drop off, and therefore we believe you’re moving from an apple to a bit of an orange in terms what you might expect. But certainly, Eastern Avoyelles Parish is into the play, and you also pick up a piece of Point Dupuy. So ground zero would be southern Amite, and then moving out from there.

Pearce Hammond – Simmons & Company International

Great, one last one from me. How many rigs do you think you’ll need to run to meet your acreage hold requirements in the TMS?

Robert C. Turnham, Jr.

Yeah, Pearce, this is Rob. The benefit of the TMS is that you can form as much as 1,280 acre units in Mississippi and call it a 1,080 acres in Louisiana. We can put two to three rigs initially in 2013, and kind of maintain that level and expect to capture our acreage. The big wild card is we’re, our footprint with Encana overlaps quite a bit, and we have a very good working relationship with those guys and change information, obviously.

So we’ll be sitting down with them and determine where their operated rig count, or rig activity is going, such that they can capture some of our minority interest in leases, and then we’ll maintain an active operated rig count also and that collectively with call it two to three rigs running, beginning. We don’t have any pressure for quite a while but we’re going to likely start doing that in early 2013, we’ll be able to capture the acreage. We have the benefit of probably 50,000 acres has a continuous drilling provision built into the leases, such that we can drill really two wells a year and maintain big box. And just like our Eagle Ford where we have the same provision, it’s going to give us great flexibility to drill at an orderly pace and not have to stress the balance sheet anymore than what we that we would want to.

Pearce Hammond – Simmons & Company International

Great, thank you very much.

Operator

Thank you for your question, Pearce. Your next question comes from the line of Cameron Horwitz of U.S. Capital Advisors. Cameron, please go ahead. You are live in the call.

Cameron Horwitz – U.S. Capital Advisors LLC

Thanks a lot, good morning guys.

Walter G. "Gil" Goodrich

Hi, Cameron.

Cameron Horwitz – U.S. Capital Advisors LLC

Rob, you mentioned the multiple options, you have here for funding, and I know you’re talking about the Tuscaloosa JV, but with what we've seen out of Comstock and the Eagle Ford and Cabot now in the Pearsall, where do the JV, either in the Eagle Ford or the Pearsall land, in terms of that funding pecking order for you guys?

Robert C. Turnham, Jr.

Yeah, that's always a possibility, and obviously evaluations in the Eagle Ford are at a real high peak, so that clearly as an option down the road. We will wait and see what the results are in the Pearsall, and either, decide to start drilling those wells or potentially look at possibly a joint venturing or farming out that depending on what that valuation is, there are plenty of options down there to raise capital in addition to what I’ve described earlier, which is we still have a huge footprint in Beckville, Minden, up in East Texas, which is Cotton Valley, it does have a probably 22% liquids component there also and plenty of horizontal Cotton Valley wells that could be drilled there. We are just, we're opportunity rich and in plenty of places to spend our money. We've just held off drilling those wells just due to being held by production. But plenty of options in excess of [JV'ing] the Tuscaloosa. So it's all about valuation and when is the right time to do so.

Walter G. "Gil" Goodrich

This Gil. I might just add one comment, which is that part of the strategy here is to move the Tuscaloosa a little further down the road, heretofore the Eagle Ford has been sole oil volume growth access and so until we can see a little bit more down the road on the TMS, we think it kind of make sense to hold on. However, we turnaround and want to run three or four rigs in the TMS next year then obviously doing something with the Eagle Ford might make a little more sense. Back to the Pearsall, our doors are open. We'd love to do something today if someone could get to a valuation as a matter of fact, we have seen with the Cabot deal.

Cameron Horwitz – U.S. Capital Advisors LLC

Sure. Okay, great. And then can you just quickly remind us how much Cotton Valley production do you have are left outside of South Henderson?

Walter G. "Gil" Goodrich

Well, if you take a ballpark number, I’ll say in the range of $15 million a day. I won’t be wrong about a more in a few million. Roughly after South Henderson. Just Cotton Valley.

Cameron Horwitz – U.S. Capital Advisors LLC

Great, thanks a lot.

Walter G. "Gil" Goodrich

Thank you.

Operator

Thank you for your question. Your next question comes from the line of Kyle Rhodes from RBC. Kyle please go ahead. You are live in the call.

Kyle Rhodes – RBC Capital Markets, LLC

Hi guys.

Walter G. "Gil" Goodrich

Hi, Kyle.

Kyle Rhodes – RBC Capital Markets, LLC

Just a question; one rig in the Eagle Ford is that enough to hold your acreage over the next one to two years?

Walter G. "Gil" Goodrich

Yes it is. We again have the benefit of big leases continuous drilling provision, built into those leases, so we could, in essence, almost in perpetuity keep one rig running and hold the acreage, which is a great flexibility for us.

Kyle Rhodes – RBC Capital Markets, LLC

Okay, thanks guys.

Walter G. "Gil" Goodrich

Thanks.

Operator

Thank you for your question. Your next question comes from the line of Dan McSpirit with BMO Capital Markets. Dan, please proceed. You are live in the call.

Dan McSpirit – BMO Capital Markets

Thank you folks. Good morning.

Walter G. "Gil" Goodrich

Good morning.

Dan McSpirit – BMO Capital Markets

On the TMS, regarding a JV or other such financing, do we see the company add more acreage before such an event, and do you need to retain operatorship, and then lastly can you remind us of your cost basis on acreage perspective for the TMS?

Robert C. Turnham, Jr.

Yeah, absolutely. Our lease acquisition for the most part is completed, except we may add whispering interest, small interest in drilling units, if we run title and find that it's unleased. I think that’s likely a 132,000 net acres gives us the most leverage of any company in the play, and I don't need to tell you if it's 5,000 or 10,000 an acre, it's a company maker for the company already. So I think it’s less likely we spend more money there, we are now transitioning into spending the development dollars to prove the play up. You said, what were the two other questions? I am sorry, I couldn’t.

Dan McSpirit – BMO Capital Markets

Do you need to retain operatorship if you do go by the way of a JV and financing that growth? And then lastly, can you remind us of your cost basis?

Robert C. Turnham, Jr.

Yeah we’re 225 bucks an acre, roughly, into it. I think that’s on the cover sheet of management presentation. So we’re in awfully cheap. Dan, our plan at this point, is to either finance it or chase it and maintain operatorship but look obviously at 10,000 an acre, or greater, you know it’s a $1.3 billion of value and it’s 35 bucks of shares. So money talks and the valuation talks, but at this point in time we’re in it to develop but until if you will see the right numbers and the right valuations. But it’s all about returns for our shareholders as you know we own 28%. It’s all about trying to do the right thing for the shareholders. So it depends on valuation.

Dan McSpirit – BMO Capital Markets

Got it. And then, if I may, based on your own internal models on recoveries, potential recoveries from the TMS, and again, recognizing that it’s very, very early innings here, but if we assume a $10 million well cost, and of course based on a whole host of other assumptions I mean, what recoveries are you looking for to make that economic?

Robert C. Turnham, Jr.

You’d be surprised at $10 million how low you can go relative to EURs and still have a very attractive rate of return. It all depends on shape of the curve, obviously. We get Louisiana light, sweet pricing, and by the way, I hear all the prophets saying how the margins that that spread between TI is going to definitely narrow. And it may narrow but right now it’s in an even bigger premium than what we saw a month ago. That’s an advantage. Lower royalty burdens is an advantage. We certainly think we have a shot at a 0.5 million to a 1 million barrels here, depending on shape of the curve. And to get that shape of the curve, we need optimum lateral length to optimum completions, and flow it back up tubing with artificial lift to really know where we’re headed. But we can’t argue, Encana, I think put out a 730,000 barrel EUR, estimate. And frankly, we see how you get there but again too early to tell.

Walter G. "Gil" Goodrich

And I’ll just add one more thing you certainly don't need to get anywhere close to that to have a very economic well.

Dan McSpirit – BMO Capital Markets

Got it, okay. And then lastly just turning to the balance sheet here, and considering the proceeds from the divestiture of the East Texas properties, and then the increase spending in the TMS this year and what it may look like in 2013. Can you give us some guidance based on your own internal models on debt-to-EBITDA, what that might look like at the end of this year and even at the end of next year?

Robert C. Turnham, Jr.

Well I’ll tell you, the sale has obviously helps a lot on just that calculation. We’ll take the proceeds in, we think, we’re still working on our tax situation, but likely with the basin of the NOL carry forwards, we’re going to realize just about all of that of those proceeds. We’ll then take those proceeds and pay down debt, and then overtime gradually borrow it back until such time that we’re cash flow neutral. And as Gil said, that delta between CapEx and cash flow is continuing to narrow to a point where it’s just going to be pretty easy to see that debt-to-EBITDA continue to drop way away from the 4 to 1 that everyone seems to follow. So if our calculations clearly did, work our way towards 3 to 1, I would say but it’s going to take some time to get there.

Dan McSpirit – BMO Capital Markets

Got it. And what might a three rig CapEx number look like for 2013?

Robert C. Turnham, Jr.

Well, what’s interesting, everybody obviously focusing on higher well cost and the TMS relative to the Eagle Ford, but when you think about our rig, while you’re drilling these horizontal wells whether it’s the Eagle Ford, or the TMS you’re spending call it $75,000 to $100,000 per day. And that doesn’t matter, where you’re drilling those wells. The completion costs, we think would success in the TMS those wells; those costs come down just because the vendors move into the area. So a three rig program depending on what your assumption is on an average working interest, you can get to where you drill, call it six wells a year that gets you 18 gross wells. Take on an average two-thirds working interest in that that gets you in a similar range to what we’re spending in the Eagle Ford.

Dan McSpirit – BMO Capital Markets

Got it. Many thanks.

Robert C. Turnham, Jr.

And then again, to follow up on that, so far what we're seeing is very attractive production rates, even though you're cycling in fewer wells, the added production, the added economic benefit of the LLS pricing and lower royalty burdens. Yeah you can drill fewer wells in the same amount of money and have equal to is not greater impact to your cash flow.

Dan McSpirit – BMO Capital Markets

Thanks again.

Robert C. Turnham, Jr.

Thanks.

Operator

Thank you, for your question. Your next question comes from the line of Richard Tullis, the Capital One Southcoast. Richard, please go ahead, you’re live is in the call.

Richard M. Tullis – Capital One Southcoast, Inc.,

Thank you. Good morning, everyone.

Robert C. Turnham, Jr.

Hi, Richard.

Richard Tullis – Capital One Southcoast, Inc.

Just a couple more and I don't think have been touched on yet. Rob, when do you plan to release the our mid-year reserve report.

Robert C. Turnham, Jr.

Yeah, probably September, maybe, is that right or October.

Jan L. Schott

Third quarter release that.

Robert C. Turnham, Jr.

Yeah. It could be the third quarter release, Richard. It’s we're just started on that. They're working through it right now, so we don't have a number and won't have a number for quite some. We'll obviously use that to get a new borrowing base also, so I think, likely that makes sense, we’ll include in our third quarter earnings release.

Jan L. Schott

Early November.

Richard Tullis – Capital One Southcoast, Inc.

I know you're a bit hesitant to talk about the asset sale's impact, but how do you see all that shaking out, as far as the borrowing base goes? Do you think the ads can help offset the production in reserve fall-off from the sale?

Walter G. "Gil" Goodrich

Yes, Richard, this is Gil. Clearly there'll be some fall off from the sale, I think exactly how much is still a bit of a question relative to mid-year and where we'll be there. So we'll kind of set that aside. Obviously we believe we’re significantly increasing overall liquidity by the sale. We're certainly not getting anything like $95 million of credit. We don't know exactly where their pricing is going to be. It looks like that the bias is towards a little bit better pricing on oil and about flat to slightly down on gas from where they were at the end of last year, so the bank group needs to resolve that.

So one of the tenants the company is we never get in front of our bank group, they get to decide what the borrowing base is. But we feel like that there's every reason to kind of maintain the 265 number at least if not – if not a little bit of improvement, given the oil wells we've drilled the first half of this year.

With the declining CapEx to cash flow delta, the incremental liquidity from the sale and the growing oil volumes quarter-over-quarter out throughout 2013 we are pretty confident that liquidity is not going to be an issue and we'll have great flexibility throughout next year. And the borrowing base itself will be growing over time as we continue to add oil volumes to the mix.

Richard Tullis – Capital One Southcoast, Inc.

Okay. What percentage of your Cotton Valley horizontal potential do you think South Henderson represented, or another way to ask what do you still have left in Minden, Beckville

Robert C. Turnham, Jr.

Yeah, Richard, go to our inventory chart in our management presentation. You will find the answer to both of those questions. We kind accounted for our probable number of locations for the Cotton Valley Taylor Sand in each of those areas and you will see reserve exposure in those also.

Richard Tullis – Capital One Southcoast, Inc.

Okay. And then finally, how do you view the Buda going forward? I guess it sounds like it ranks below Tuscaloosa and Eagle Ford. I mean any plans do anything there as you go into next year.

Robert C. Turnham, Jr.

Richard yeah, Rob again, very well could, but there is no additional Buda wells on the schedule through the end of this year. As we've talked before, the variability of those wells it just but that is hard to predict the outcome of some wells that are of the charts and some that are less than desirable. So based on all that we have on our plate, we're comfortable with reallocating a little bit of capital to the TMS and still maintaining the one rig drilling Eagle Ford wells, but the caveat also being if the Pearsall develops then we have another item to consider.

Richard Tullis – Capital One Southcoast, Inc.

Very good, thank you.

Robert C. Turnham, Jr.

Thank you, Richard.

Operator

Thank you for your question Richard. Ladies and gentlemen we have time for one more question after our next question from Michael Hall of Robert W. Baird. Robert, please go ahead you’re live in the call.

Michael Hall - Robert W. Baird & Co., Inc.

Thanks good morning gentlemen.

Robert C. Turnham, Jr.

Hi, Mike.

Michael Hall - Robert W. Baird & Co., Inc.

I guess just quickly on my end, any, have you considered or looked at the potential to use any sort of this preferred financing in the TMS? Is that an avenue would you consider going, or do think a JV is probably more likely?

Walter G. "Gil" Goodrich

Michael, this is Gil. We will be at the appropriate point in time open to all proposals. Yes, we’ve had some discussions with people. We're certainly cognizant of the deals that have been done by Chesapeake and others, that are kind of property preferreds, and we'd be open to that. Obviously, where our stock is trading today, we would be moving any type of corporate preferred that will be convertible into our common way down the list of priorities, if even on the list. So I think we'll see where valuations land as we move to advance the ball another six months or so, and open it up to pretty wide, cast a pretty wide net and see what comes up, but we'd be open to that type of thing. Yes.

Michael Hall - Robert W. Baird & Co., Inc.

Okay, fair enough. And then, sorry if I missed it, but any comments or plans in terms of testing the Pearsall on your own any timing on that?

Robert C. Turnham, Jr.

Yeah, Michael, it’s Rob. It just depends on offset operator completions. If it looks awfully attractive, then we are going to be tempted to reschedule and test it. Or, if we had options like Gil described to bring in additional capital by selling or entering into a transaction we would consider that. But we are not just going to sit there and let it sit if it has got great potential, but at this point just too early to make those plans.

Michael Hall - Robert W. Baird & Co., Inc.

Okay, fair enough. Actually, I jumping back on the TMS are there any, or again, sorry if I missed this, but are there any production volumes planned in the current budget from that? I mean I would assume, like you said, the cycle times change when you move from the Eagle Ford to the TMS, just trying to get a sense for timing an impact on production?

Robert C. Turnham, Jr.

Yeah, there is very little TMS associated with the rig move because of the lag time once we move the rig from the Eagle Ford to the TMS. We’re going to be drilling wells that will not get production until early 2013. As to the financial model, as to our projections, we do have some Tuscaloosa volumes obviously from the wells we drilled so far, and we've risked the volumes. We’ve taken up a risked Eagle Ford type curve and applied that to, for example, the Denkmann well and some of these additional Encana operated wells. So we do consider that. We do try to be conservative on timing and we risked the curve. Since we’re just so early in this play. We prefer to do it that way. But the vast majority of the oil volume growth will continue to come from the Eagle Ford.

Michael Hall - Robert W. Baird & Co., Inc.

Okay. And on that oil volume growth, I mean, I pretty sure you confirmed the year-end exit rate target. The full-year oil guidance is that still fair or how should we think about that?

Robert C. Turnham, Jr.

Obviously, if you plug in a number that gets you to the 5,000 barrel a day exit rate then the year-over-year comparison is going to be a bit challenged and it’s just due to delays and fewer wells getting completed. So the math it’s just going to be a bit challenged there. You’re still going to see dramatic growth year-over-year and we’re focused on the timing as we exit the volume, as we exit the year. You’ll just see those volumes roll into 2013 just due to timing issues.

Michael Hall - Robert W. Baird & Co., Inc.

Okay. And last one of mine, any tax impacts on the sale in East Texas or is that pretty much no tax impacts there?

Robert C. Turnham, Jr.

We’re working on that Michael but, we do have a fairly good basis there at South Henderson, cost basis, and we do have a NOL carry forwards. So, as we sit here right now, we wouldn’t expect a material tax expense certainly associated with that, certainly not a cash and tax expense.

Michael Hall - Robert W. Baird & Co., Inc.

Okay, actually, one last one and are you disclosing the production volumes associated with the sale?

Robert C. Turnham, Jr.

We have not, no, under a confidentiality agreement on details relative to the sale. At the appropriate time, we and the buyer will likely disclose more details associated with that in a conservative effort. We’ll jointly announce that but at this point all we can do is refer you to previously provided information that’s in the market already.

Michael Hall - Robert W. Baird & Co., Inc.

Fair enough. Well congrats on getting it done. Thanks guys.

Walter G. “Gil” Goodrich

Thank you.

Operator

Thank you. Ladies and gentlemen that’s all the time we have for questions. I would now like to return the call back over to Gil Goodrich for closing remarks.

Walter G. “Gil” Goodrich

Thank you Emily and thank you everyone for your participation. This morning we’ll be look forward to providing you our third quarter results in early November.

Operator

Thank you for joining today’s conference. This concludes the presentation. You may now disconnect.

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