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Goodrich Petroleum Corporation (NYSE:GDP)

Q2 2008 Earnings Call Transcript

August 7, 2008 11:00 am ET

Executives

Gil Goodrich – Vice Chairman and CEO

Rob Turnham – President and COO

David Looney – EVP and CFO

Analysts

John Freeman – Raymond James

David Heikkinen – Tudor, Pickering, Holt & Company

Ron Mills – Johnson Rice

Scott Wilmoth – Simmons

Kim Pacanovsky – Collins Stewart

Richard Tullis – Capital One Southcoast

Dan McSpirit – BMO Capital Markets

John Healy [ph] – Forest Investment Management

Operator

Good day, ladies and gentlemen and welcome to the second quarter 2008 Goodrich Petroleum earnings conference call. At this time, all participants are in a listen-only mode. We will be facilitating a question-and-answer session towards the end of today's conference. (Operator instructions) As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today's conference, Mr. Gil Goodrich, Vice Chairman and CEO. Please proceed, sir.

Gil Goodrich

Good morning, everyone, and welcome to the second quarter conference call. We are anxious to get started, but let me first begin with an introduction of the executive officers and directors that are on the phone with us this morning, beginning with Pat Malloy, the company’s Chairman of the Board; Robert Turnham, our President and Chief Operating Officer; David Looney, our Executive Vice President and Chief Financial Officer; and Mark Ferchau, our Executive Vice President and Director of Engineering and Operations.

We’ve put out a detailed press release after the market close yesterday detailing our operational update and earnings for the second quarter. If for some reason you did not get a copy of that and would like one, you be feel free to call my assistant, Becky Delatin, at 713-780-9494. She will be happy to fax or e-mail you a copy. And you can also access it on our website at www.goodrichpetroleum.com. As is our practice, we’d like to remind everyone that there may be comments that we may make and answers to questions that we may give during this teleconference, which may be considered forward-looking statements that involve risks and uncertainties and we have detailed for you in our SEC filings.

During all of the recent market volatility we have remained focused on the execution of our strategy for building long-term value for our shareholders and we believe this quarter results illustrate the progress we are making and the success of our strategy. Through our aggressive Cotton Valley trend development activities, which reached a record pace of drilling during the quarter with conducting operations on 46 wells during 2Q, net production volumes grew at a very rapid pace. Our net production volumes exceeded the high end of our internal estimates and averaged just over 67 million cubic feet of gas equivalent per day representing a very strong sequential growth of approximately 16% when compared to the first quarter of this year.

Very strong net realized prices, which averaged $10.62 per Mcfe during the quarter coupled with the excellent production growth led to record revenue with just over $65 million. In addition, our cost control efforts were [ph] total operating expense were down by just over $1 per Mcfe on a unit basis compared with the prior year’s period and down 7% sequentially from the first quarter of this year has allowed us to effectively leverage off of our robust production volume growth and consequently operating income for the quarter expanded dramatically to approximately $16 million.

As you are aware, natural gas prices and the future strip increased significantly during 2Q and resulted in a correspondingly significant increase in the liability of our forward hedge position, resulting in a loss on derivatives in the quarter of approximately $49 million. After reversing out this predominantly non-cash charge, we would have reported positive net income for the quarter. With the recent declines in the natural gas market since the end of the quarter, a significant percentage of our mark-to-market hedging liability has been reversed in the last 45 days. And although we would love to report an expanded liability at the end of 3Q, which would mean that our gas markets had regained momentum and increased, we would likely see a reversal and a gain associated with our hedging position in 3Q.

Cash flow, a very strong indicator of our ability to fund a larger percentage of our capital expenditures through our operating activities, also increased dramatically in the quarter with EBITDAX reaching in excess of $46 million. Operationally, we not only continued with the very active development of our core Cotton Valley Trend reservoirs, but also made great progress in further delineating the Haynesville Shale across our acreage position in Northwest Louisiana and East Texas.

We have now drilled eight vertical Haynesville Shall wells in the Bethany-Longstreet, Caddo Pine Island, Beckville and Minden fields, and are currently drilling on two additional vertical Haynesville tests. The eight wells across the acreage have encountered (inaudible) thicknesses for the Haynesville Shale ranging between 120 feet and 275 feet of thickness with initial production rates from the shale in six wells, which we’ve given test information on it ranging between 1 million cubic feet of gas per day and 2.6 million cubic feet of gas per day.

Finally, with the closing of our joint venture with Chesapeake Energy on July 15 and our follow-on equity offering closing on July 14, we’ve brought in a combined $265 million and are extremely well positioned to take full advantage of the deep inventory of opportunities currently in front of us and we are excited about the initiation of the horizontal development of the Haynesville Shale, which will begin later this month.

I’d now like to turn the call over to Rob Turnham for a more detailed review of our second quarter results.

Robert Turnham

Thank you, Gil. We continue to be focused on production volume and reserve growth at the drill bit. And the second quarter, as Gil said, was an exceptional quarter on both fronts. Our gross Cotton Valley Trend production volumes grew to a record 112 million cubic feet equivalent per day. And as Gil stated earlier, our net volumes for the quarter averaged 67.1 million per day, which was well above the upper end of our guidance and 16% sequential growth rate over the first quarter. We combine that with the 15% sequential growth we had in the first quarter. The company is well positioned to meet or beat consensus estimated volume growth for 2008. In fact, if you take the low end of the third quarter guidance being 72 million a day and hold that flat for the quarter. We will exit 2008 with production growth in excess of 15% over 2007, and very little of that growth will come from the Haynesville Shale.

We had 343 Cotton Valley Trend wells producing as we exited the quarter with six in completion phase, with a success rate in excess of 99%. Of the 343 producing wells, 103 were at Minden, 71 at Beckville, 69 in the Angelina River Trend, 44 at Bethany-Longstreet, 30 at South Henderson, 12 at Longwood, and 14 on other acreage outside of our core areas.

We conducted drilling operations on 46 wells during the quarter with approximately 11 rigs running, eight of which we operated. Of the 46 wells, in which we conducted drilling operations, 19 were drilled at Angelina River, with 16 being Travis Peak wells and three being James Lime horizontals. Nine were at Minden, three at Beckville, four at South Henderson, nine at Bethany-Longstreet, and two at Central Pine Island in North Caddo Parish.

For the quarter we completed 35 wells in six fields with an average initial production rate in excess of 2.7 million cubic feet per day, which is approximately 800 Mcf per day or 45% higher than our historical average. Of the 35 wells completed during the quarter, 15 were in Angelina River with an average initial rate of 3.9 million per day; six were at Minden with an average initial rate of 1.8 million per day; six were at Bethany-Longstreet with an average initial rate of 1.5 million per day; three were at Beckville with an average rate of 1.5 million cubic feet per day; three at South Henderson with an average initial rate of 1.8 million a day; two at Central Pine Island, which we were still completing as of June 30.

We are on pace to drill 140 to 150 wells in 2008 and our drilling plans will continue to be focused on a number of catalysts. First, we will continue to drill in proven areas of our core Cotton Valley Trend acreage with emphasis on vertical wells in areas in which we – in which our expected reserves and rates of return are favorable in today’s commodity price environment. Second, maintain an active drilling program in the Angelina River Trend, drilling both the vertical Travis Peak wells where results in the second quarter were exceptional and horizontal James Lime wells. And third, continue to de-risk the acreage for the Haynesville Shale by drilling a handful of additional vertical wells prior to the commencement of horizontal development beginning later this month.

As to our rig fleet, five of our eight operated rigs are currently capable of drilling horizontal wells. And if results come in as expected in the future, you will see greater emphasis on horizontal development in 2009. Focusing on some of our core areas, at Bethany-Longstreet we have one rig currently running drilling Cotton Valley Hosston dually completed wells, and anticipate the initial Chesapeake operated rig in the field by the end of the month to commence our horizontal Haynesville Shale development in the field. We are expecting a second Chesapeake rig in the field in the fourth quarter.

At Central Pine Island in Caddo Parish, we’ve recently completed our E&L Development Number 1, which had 276 feet of Haynesville Shale thickness. We completed it at 1.1 million a day and are currently completing the second vertical well in the field called the Hall 5 Number 1. Both of these wells are vertical pilot holes in which we own a 50% interest. We have plans to drill at least two additional vertical wells in the field prior to horizontal development set to commence in early ’09. The company owns a 50% interest in these wells and 5,800 gross acres.

Moving to Texas, we continue to be very pleased with the results in our Angelina River Trend where we own an average 58% working interest in 70,000 gross, 40,500 net acres. This area has substantial potential for the company and that we have two plays working simultaneously. Travis Peak vertical wells, which are typically drilled to a little less than 12,000 feet, and horizontal James Limes wells, which we see at about 9,000 feet.

For the quarter we participated in drilling operations on 16 vertical Travis Peak wells and completed eight, all of which had the James Lime present with gas shows. The Travis Peak wells had an average initial production rate of 3.7 million per day driven by very good primary completions in the Travis Peak, but many of the wells were commingled with the Pettit, which added to the rate in ultimate reserve.

We have completed two James Lime horizontal wells during the quarter at an average initial rate of approximately 6 million per day. Our Kirkland 1H, which was a well in which we own 87.5% working interest in the far southern end of our Allentown Prospect area had an initial production rate of 3.3 million per day, and the Ron Mills 1H well in our Cotton Prospect area, in which we own a 57% working interest, averaged 8.5 million per day over a 72-hour period.

Significantly we are currently drilling our initial James Lime horizontal well on our Cotton South Prospect, which we call the Bob Sessions 4H, in which we own 100% working interest and where we had never accounted for the reserve potential in our inventory chart. We expect completion results on that well in 45 to 60 days. We continue to see very good results in the Southeastern portion of our Minden Block as well as South Henderson where we now have completed our initial 20-acre spaced well with no apparent communication with the offset well.

I would like to now turn it over to David Looney to walk you through the financials.

David Looney

Thank you, Rob. Reported revenues for the second quarter of 2008 of $65.2 million were based on average realized prices of $10.18 per Mcf for gas and $121.51 per barrel for oil. On gas, you may recall that we had 28.5 million cubic feet a day sold under physical contracts at a fixed price, adjusted by about $8 during the quarter.

After adjusting for those volumes, our average price on the remaining volumes of gas was approximately equal to the weighted average Henry Hub price during the quarter. This situation was really a function of a greater percentage of our non-fixed price volumes being sold during the last couple of months of the quarter, which were higher prices. Thus we really do continue to expect our average differential on non-fixed price volume to continue to be a deduction from the Henry Hub price of anywhere from $0.20 to $0.50 per Mcf.

On oil, we realized an average basis of about $2.50 off of WTI Cushing prices during the quarter. None of these prices include the impact of $1.8 million in realized losses on our hedge portfolio during the quarter. Also during the quarter as in previous quarters, none of our gas hedges were designated as hedges for accounting purposes. Thus the entire change in the mark-to-market value of the contracts much run through the income statement, in the line item, gain or loss on derivatives not designated as hedges. And as a reminder, we currently have no oil hedges in place.

Looking at cash flow, as Bill mentioned, our EBITDAX for the second quarter of 2008 increased to $46.4 million or $1.44 per basis share versus $18 million or $0.71 per share for the prior year’s period. Similarly, discretionary cash flow, which is defined as net cash from operations before changes in working capital, increased to $41.5 million for the quarter versus $15.4 million during the second quarter of 2007.

Focusing on the expense side of the income statement, our lease operating expense in the second quarter was approximately $7.7 million or $1.26 per Mcfe on a unit basis versus $6.2 million or $1.65 per Mcfe in the second quarter of 2007 and also $7.1 million or $1.35 per Mcfe in the first quarter of this year. LOE for the second quarter of 2008 included $0.04 per Mcfe for workover expenses versus $0.18 per Mcfe for workovers during the first quarter of the year. Thus when you exclude the impact of workovers and abandonment expenses, the LOE per Mcfe rate was fairly positive during the first two quarters of this year. And at a $1.19 per Mcfe average for the first six months, it was really just below the midpoint of $1.10 to $1.30 range we had previously suggested.

For the next quarter, we don’t expect to see any material change in this per unit expense. No change will likely occur until new salt water disposable facilities are in place and fully functional in our North Minden field and the Cotton South area of the Angelina River Trend, which is not expected to occur until sometime in the fourth quarter.

Production and other taxes of $2.3 million for the second quarter of ‘08 included production tax of $1.7 million and ad valorem tax of $0.6 million. Production taxes were net of $0.8 million of tight gas sands credits we booked for our wells in the State of Texas during the quarter. By comparison, during the second quarter of ‘07 we actually booked TGS credits in excess of our severance taxes, thus resulting in a negative balance of $590,000 during that quarter for production and other taxes.

You might recall that the first half of ’07 was actually the first period during which we booked a material amount of TGS credits due largely to a greater number of backlog credits being approved by the State of Texas. When compared to our revenue of $65.2 million, this net production and other tax line item of $2.3 million is approximately equal to 3.5% of total revenues, which is a very attractive level for us.

Transportation expenses totaled $2.4 million in the second quarter of ’08 or $0.39 per Mcfe versus $1.4 million or the same $0.39 per Mcfe in the second quarter of ’07. As we’ve mentioned on previous calls, our current production mix is resulting in a fairly level range of per Mcfe transportation expenses, again, anywhere from $0.35 to $0.40 on a regular basis.

DD&A expense totaled $29 million for the second quarter of this year or $4.75 per Mcfe versus $19.5 million or $5.24 per Mcfe in the second quarter of last year. We calculated first and second quarter 2008 DD&A rates using the December 31, 2007 reserve information. And I’ll remind everyone that as a successful efforts company, we are required to deplete our total capitalized drilling and completion costs over only the proved developed portion of our reserves. We expect to have a mid-year reserve report completed within the next 30 to 60 days, and we would expect to use that report to determine DD&A rates for the remainder of 2008.

Exploration expenses for the second quarter of ‘08 were flat with the prior year period at $1.8 million, but on a per Mcfe basis, they were down to $0.29 an Mcfe from $0.48 per Mcfe in the second quarter of ’07. Amortization of undeveloped leasehold cost, which is a non-cash item, was $0.9 million of the total amount during the second quarter of this year. Again as a reminder, as new areas are developed and proven successful, the resulting acreage costs per transfer to the proved producing category and included in the DD&A rate.

G&A expense increased slightly on an absolute dollar basis to $5.9 million in the second quarter of ’08 from $5.5 million in the second quarter of ’07, but it experienced a 34% decrease on a per Mcfe basis to $0.97 per Mcfe during the second quarter of this year from $1.48 per Mcfe last year.

Stock-based compensation expense, which is again a non-cash item, amounted to $1.3 million for both the second quarter of ’08 and the similar period last year. As we pointed out on previous calls, our cash G&A expense has been relatively flat now for the last six quarters averaging approximately $4.1 million per quarter during that period.

Finally, for the three months ended June 30, 2008, we reported a net loss applicable to common stock of $39 million or $1.21 loss per basis share on total revenue from continuing operations of $65.2 million as compared with a net loss applicable to common stock of $4.8 million or $0.9 per basic share on total revenues from continuing operations of $28 million for the three months ended June 30, 2007. As Gil mentioned, the majority of this year’s loss resulted from a $48.9 million pretax loss on derivatives not designated as hedges during the quarter. The vast majority of which was non-cash. Additionally, as Gil mentioned, a large portion of that loss would have been regained as commodity prices have fallen since the June 30 determination date for the mark-to-market calculation.

Turning to the balance sheet, while the June 30 balance sheet shows the impact of neither our recent equity offering nor our transaction with Chesapeake, suffice it to say Goodrich Petroleum has never been in as strong a liquidity position as we currently find ourselves. Having raised over $365 million of new capital as a result of these transactions in early July, we are entering the latter part of the third quarter with over $360 million in cash in short-term investments and zero of outstanding on our senior revolving credit facility.

When the new borrowing basis established after we delivered the midyear reserve report, which should be within the next several weeks. We would expect to see a total liquidity number that is cash plus unused availability in excess of around $450 million. When you combine this with our growing production and cash flow profile, we proceed moving well into the 2010 to 2011 time frame before we would need to pursue any external financing arrangements given the current level of commodity prices.

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

Gil Goodrich

Thank you, David. Well, as we look forward and as David just mentioned, we find ourselves in far and away the best liquidity position we’ve ever been in and we plan to take full advantage of this extraordinary opportunity not continuing with our active development of our core properties and adding an aggressive startup for horizontal development of the Haynesville Shale.

Our 2009 capital expenditure budget is not complete not approved by our Board of Directors. We do expect to invest a minimum $100 million next year in our joint venture with Chesapeake Energy and essentially that much again drilling horizontal Haynesville wells on our non-JV acreage across Northwest Louisiana and East Texas. Based on all of the data we have to date from industry and including the eight wells we have drilled, logged and cored, and the production data we have seen thus far, we are confident that Haynesville Shale will become an important complement to our core activities. And if demonstrated success and as we anticipate, you will likely see us reallocate additional capital into the play during 2009.

We appreciate your participation this morning. Look forward to reporting third quarter results and are happy to take any questions you may have.

Question-and-Answer Session

Operator

(Operator instructions) Your first question comes from the line of John Freeman of Raymond James.

John Freeman – Raymond James

Hi guys, great quarter.

Gil Goodrich

Thanks, John.

John Freeman – Raymond James

First, on just the traditional Cotton Valley, it seems like consistently here in the past several quarters we have seen the average IP rate on those wells go up. Is that just kind of a high-grading of your prospect? Do you do anything differently in these last few quarters on the completion side or kind of a combination of both?

Gil Goodrich

Rob, I’ll take that. John, first, good morning. I think it’s a combination of things. Yes, we are always continuing to tweak and refine and hopefully better select the specific intervals we want to complete in our fracs. I’d say a big contributor obviously is the blending in of higher performance type reservoirs, i.e., the James Lime horizontal drilling that we’ve done, and collectively that’s just resulted in more positive results across the board.

John Freeman – Raymond James

Okay. And then just following up on your comments, Gil, in terms of kind of the preliminary kind of outlook for the CapEx budget in ’09, it would seem to indicate, which is based on your comments on the CapEx towards the Haynesville of about couple of hundred million and relative to the OE CapEx budget $350 million that is it kind of safe to assume that in ’09 that unlike the past, majority of your CapEx is going to be devoted towards Haynesville, maybe to a lesser extent to James Lime and then the Cotton Valley, kind of high-grading where the highest return projects are the ones getting the majority of the CapEx.

Gil Goodrich

John, I think that’s fair. Obviously we don’t want to get our in front of our board on either the allocation or the absolute amount of 2009’s program. But I think it’s fair to kind of think of us as maybe slightly decreasing the Cotton Valley, Travis Peak, James activity and replacing that plus quite a bit with Haynesville Shale. So, is it 400 or 450? It’s a little early for us say. But I think that’s a fair enough range for people to kind of be looking at in terms of our ’09 program.

John Freeman – Raymond James

And is the majority of your acreage by the end of the year on the traditional Cotton Valley, will that be held by production?

Gil Goodrich

Well, we still have a little – I guess that Angelina River is probably the place we still have a fair amount of continuing development, but we’re in a good solid position in terms of our leases and time left on them. The vast majority of Northwest Louisiana and East Texas, we think, will be nailed down certainly by the end of this year. Some of it already is.

John Freeman – Raymond James

Okay. And then last question and I’ll let someone else get in. Of the eight rigs that you have currently operating, what’s kind of the breakdown of those rigs in terms of how many are kind of term contracts, how many will roll off here in the near-term?

Rob Turnham

This is Rob. First of all, of the eight, about five are capable of drilling horizontal wells. They are staggered. I’d say we probably have three or four contracts that again over the next six to nine months will roll over, some of which we’re happy to roll over, some of which we may switch out for more efficient rigs. We do have – of those five that can drill horizontal, they do have top drives, they do have pump size adequate to drill the Haynesville Shale wells. So, current rig rate is still for our fleet about 18,500 a day. Depending on size and whether we go add to our horizontal capabilities. Certainly without on top drive, that market is probably 17, 17.5 a day and then the typical top drives are 2,500 or 3,000 a day.

John Freeman – Raymond James

Great. Thanks guys, I appreciate it.

Gil Goodrich

Thank you, John.

Operator

Your next question comes from the line of David Heikkinen of Tudor, Pickering, Holt & Company.

David Heikkinen – Tudor, Pickering, Holt & Company

Good morning guys, and nice quarter.

Gil Goodrich

Thanks, David.

David Heikkinen – Tudor, Pickering, Holt & Company

Just thinking about – you talked about delineating the Haynesville, just wanted to be crystal clear on amount of acreage that you see in the Chesapeake joint venture and what that is on a net basis and then the non-JV acreage that you now see as prospective for the Haynesville?

Rob Turnham

Yes, I’ll take that. This is Rob. As we’ve said in the past [ph], we feel like and we are comfortable with 60,500 net acres currently due to well control that would encompass about 22,000 net acres in North Louisiana. Of that, about 10,500 net acres, I believe is the number, would be associated with the – actually it’s a little bit more than that. We sold 10,500 net acres to Chesapeake. That would be Bethany-Longstreet and Longwood. I think that net remainder – let me back into that. We have Central Pine Island, we have a 50% interest in 5,800 acres, so that’s 2,900 acres. And then Longwood and Bethany-Longstreet would comprise roughly the difference. So, little less than 20,000 net acres would be associated with the Bethany-Longstreet and Longwood joint venture. Moving over into East Texas, we are really basically just taking in our Minden and Beckville fields where we have about 38,800 net acres over there. There is potential. And not only us, but other operators are continuing to kind of step out and test the limits of the Haynesville. We’ve not included South Henderson yet and then Angelina River where we have 40,000 net acres, it certainly would be deeper. It’s further south. It is on trend with some of the things that, Cabot in particular, where they are testing at Trawick and then at County Line. But we have not included that in our number.

David Heikkinen – Tudor, Pickering, Holt & Company

Okay. And as you think about your delineation program with vertical wells, are you doing anything at South Henderson or down in the Angelina River Trend, or are you not delineating that and just kind of letting the industry test that area?

Rob Turnham

Yes. We do have plans to test at South Henderson with a vertical well. And you probably will get results on that over the next, I would say, 60 days. Again, without the well control, it’s too hard to say right now whether it’s prospective or not, but certainly we are trying. And then we are a fairly time away from testing in Angelina River. We feel like some of the other competitors will do that for us probably quicker than what we have scheduled. So I would say, if we test it down there, it will be another probably three to six months.

David Heikkinen – Tudor, Pickering, Holt & Company

And how do you think about additional joint ventures? I mean, you don’t need it from a financial standpoint, is there any need from an operator leverage and just from a people standpoint, rig standpoint that would drive that, or do you feel like you are pretty well set to operate your plan from here forward?

Gil Goodrich

Well, I will tell you, the reason we did a joint venture with Chesapeake was twofold. One, the equity was nice, bringing in $173 million, but two, we feel like they are the early mover in the play. They have done more research on the rock and the mineralogy work that is necessary. They probably have been able to tweak the drilling and completion so that it would expedite our learning curve versus us doing it ourselves. However, once we have that experience with them, the second part of our reason for doing it was to be able to transport that over into East Texas and carry that expertise with us. And frankly, we don’t see the need at this point in time for additional joint ventures. We are well capitalized with $265 million of cash on the balance sheet and will have that expertise that allows us to operate and develop the rest of our acreage.

David Heikkinen – Tudor, Pickering, Holt & Company

Thanks guys. I’ll let other people jump in.

Gil Goodrich

Thanks, Dave.

Operator

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

Ron Mills – Johnson Rice

Good morning. A little bit of follow-on to one of the earlier questions for either of you, Gil or Rob, if you end up do spending the $400 million under the – net to you [ph] under the Chesapeake JV and $100 million on Goodrich acreage alone next year, what kind of drilling activity would you expect that that would allow you to drill in terms of well count? Is it 25 to 30 wells?

Gil Goodrich

I’ll jump in on that, Ron. This is Gil. I would say that on a gross basis, it’s probably closer to 50 wells with, say, roughly 25 of those – well, maybe (inaudible) I’m sorry. Probably about 25 wells with Chesapeake and probably more like 15 Goodrich 100% wells, and not quite 50, it’s more like 45 – 35 to 40.

Ron Mills – Johnson Rice

Okay. And as you go through the remainder of this year continuing to drill vertical wells, as you look ahead to 2009, are you looking to be more exclusively a horizontal drilling including on your acreage in East Texas?

Gil Goodrich

Well, as Rob said, following up on David’s question, we do have quite a bit of acreage out there that’s currently not in the 60,500 that we are considering to be prospective at this point for the Haynesville. So we still have some vertical – call it pilot hole, if you will, delineation wells to drill. I don’t think that’s a huge number, certainly within the 60,000. It may be half a dozen to a dozen wells. And therefore, most of the real production gain and significant percentage of the capital will be going towards horizontal drilling certainly by the end of this year.

Ron Mills – Johnson Rice

Okay. And Rob, just to clarify something you mentioned on the capital allocation between the Haynesville and your Cotton Valley, Travis Peak, James Lime, I just want to make sure I heard correctly. Would the first projects to probably fall off if you are going to reallocate more to Haynesville because of the relative economics be the Cotton Valley verticals and not necessarily the Travis Peak or James Lime?

Rob Turnham

Yes, Ron. I mean, if you kind of prioritize from a rate of returns standpoint, the inventory that we have and certainly the vertical Cotton Valley wells, although 100% successful for the most part do have lower rates of return. And if you are working within a fixed budget, you certainly would minimize those wells versus some of the higher internal rate of return wells. If you look at really our inventory and you scale it from highest IRR to lowest, clearly the Haynesville Shale horizontals – and if you just basically take kind of a midpoint 6 Bcf well that is an EUR that others are talking about, we certainly don’t have any experience at that yet. $7 million CapEx – you are looking at 60% rates of return on $8 gas. If that’s working and it’s consistent across our acreage, we would – it would be only be prudent to put as many rigs doing that as we felt that would work for us. But second, after that you are looking at James well and Travis Peak wells that have very good internal rates of return and those will continue to be a piece of what we do. As Gil said, the luxury is that most of Minden and Beckville is already held by production where most of the vertical Cotton Valley wells had been drilled. So we wouldn’t be in jeopardy of losing acreage. At Angelina River Trend, those wells are working very well anyway. So we would continue to step out, drill Travis Peaks and James Lime wells, hold acreage, and they can work at a pretty low commodity price as well.

Ron Mills – Johnson Rice

Okay. And then two questions just on the Angelina River Trend, you are drilling your first James Lime test and in Cotton South despite having drilled a bunch of Travis Peak wells there in the past. Will you happen to gather more information on the James Lime, or why the activity in the Cotton – I hope I’m getting these projects right, the Cotton versus Cotton South. But you drilled the James Lime and the Cotton, but not the Cotton South, and now you’re shifting to Cotton South. What’s driven that decision?

Rob Turnham

At Cotton South, we see the James Lime present in all of the Travis Peak wells. If you remember our map, there have been quite a bit of wells drilled over there. EnCana is our partner on probably 70% of that acreage, and then we have 100% acreage at Cotton South also. And Southwestern has drilled an offset well to the James Lime that I believe they call Session 16H that has come in, looks very good and had an initial rate of 6.7 million a day if my memory serves me. So we have offset wells that look – an offset well that looks very good and we have shows in all of our Travis Peak wells. We just have not gotten down there to test it, but are excited to do so now. It’s just been – majority of activity being in the Cotton Prospect is just basically where we started. It led to additional development opportunities. We have St. Mary as a partner up there and they have been anxious to drill those wells as we have. So, it’s just a matter of getting around to it, but clearly, as we said earlier, there is no probable reserve exposure built into the inventory chart for the Cotton South area, yet we do have an offset well that looks very attractive. So we’re hopeful, but we would like to get some results before we account for that reserve –

Ron Mills – Johnson Rice

Have you included Bethune or Allentown into your James Lime?

Rob Turnham

We have not yet. In fact, the Kirkland well, which we reported in this quarter, certainly came in less than what we had hoped. It is 3.3 million a day. But it is the very southernmost acreage that we have and it’s off to itself kind of in the South-central portion of our acreage block. We still had plans to get off over east, which we call Bethune, it looks kind of like the State of Florida, and then even further east to test the James Lime on what we call East Lake. But first things first. We’d like to get a well down in Cotton South and hopefully it will come in similar to what we’ve seen in the Cotton area.

Ron Mills – Johnson Rice

And just as we watch the industry, particularly with Cabot in their Trawick and County Line areas, because I think Cabot is supposed to be drilling their first Haynesville test in the County Line area. How far, as the crow flies, are those projects from yours so that we can get a sense as to the march towards your Angelina River Trend acreage?

Rob Turnham

Gil, do you have – as the crow flies, that’s–?

Gil Goodrich

Yes. From about the center, Ron, of our Cotton Block, you’re looking at about 18 to 20 miles kind of east, northeast to get to County Line.

Rob Turnham

You do see, Ron, geologically, in fact you see it on our James Lime map, you see the trend that shows James Lime horizontals including all the private company horizontal wells that have been drilled between us and County Line. So the trend does tend to work kind of southwest, northeast. So hopefully we’ll have the same kind of geologic setting when they test the Haynesville at County Line.

Ron Mills – Johnson Rice

All right guys. Thank you.

Rob Turnham

Thank you.

Operator

Your next question comes from the line of Scott Wilmoth of Simmons.

Scott Wilmoth – Simmons

Hi guys, this is Scott.

Gil Goodrich

Hi, Scott.

Scott Wilmoth – Simmons

Just wanted to get a little more color on the increase you guys are seeing out of your Travis Peak wells and Angelina River Trend. What are you guys doing differently in those completions?

Gil Goodrich

Scott, this is Gil. In Angelina River, in terms of the James Lime, we have begun experimenting with slightly larger frac sizes, not necessarily more stages, but just more fluid, more sand content. That seems to be helping both on initial rates and flattening a little bit on the declines. And then as Rob mentioned earlier on the call as to the Travis Peak, we have – and EnCana, our partner, has particularly during the second quarter begun to add the Pettit, which is just above the Travis Peak in our vertical wells. It is not as blank, it is consistent with the Travis Peak, but we are seeing a pretty significant percentage of wells down there and we’ve just really recently begun to add that and that clearly is adding to the production for those wells.

Scott Wilmoth – Simmons

So the increase seen from Travis Peak is not so much completions, but more adding the Pettit?

Gil Goodrich

Correct.

Scott Wilmoth – Simmons

Okay, great. And then when looking at the horizontal development plan for the Haynesville, are there any well-specific differences for your North Louisiana area versus our East Texas area? And could you guys give an update on that?

Gil Goodrich

Not really. We are beginning, kind of in the early phases, particularly in East Texas, of laying out our plans. We obviously are now close with Chesapeake and are working with them and have another meeting coming up next week with them, which will lay out plans, not only the well is going to start here later this month but throughout the remainder of this year and even start to look at 2009. We don’t geologically see any difference. The section does tend to thin somewhat as you go westward. And across our Minden, Beckville block, the four wells we now have down had ranged from about 130 feet of thickness to a little over 200 feet of thickness. And that would compare with something that’s really been north of 200 in every well we’ve drilled over in Northwest Louisiana. But other than that difference, pretty broad similarities and we don’t see any faulting or anything we think is going to complicate the horizontal development.

Rob Turnham

And Scott, this is Rob. I might add, what’s interesting to us and a bit confusing is the well that has the thinnest Haynesville Shale thickness has had the highest initial production rate from a vertical standpoint of 2.6 million a day. So, what we don’t know, what we’ll need to learn over time is, obviously when you go horizontal, you would assume thicker as better as long as you have the same porosity and permeability and mineralogy. But does that mean that you are linear and that 130 feet as a percentage or 70% of the 200 feet and therefore you get 70% of 6 Bcf? That part we won’t know until we get into it. But obviously if that’s the case and you are still at 4.2 Bcf on a thinner well, the economic on that were still very attractive. But those are things that we’ll have to learn as we step out and start horizontal development.

Scott Wilmoth – Simmons

On the initial wells, any idea on lateral lengths you guys intend to use and stages of fracs?

Gil Goodrich

I’ll take a stab at that. I would just say that we certainly plan initially to be in the range of 4,000 feet. I don’t currently think it would be a whole lot more than that. It probably won’t be a whole lot less. And in terms of numbers of stages, I’d say we’d probably get end up right about where people seem to be evolving, which is eight, perhaps as many as ten stages.

Scott Wilmoth – Simmons

Okay. So, estimated cost may be $7 million, not a bad number or–?

Gil Goodrich

I think that’s fair.

Scott Wilmoth – Simmons

Okay. Thanks guys.

Operator

Your next question comes from the line of Kim Pacanovsky of Collins Stewart.

Kim Pacanovsky – Collins Stewart

Good morning guys. Congratulations on the quarter.

Gil Goodrich

Thank you, Kim.

Kim Pacanovsky – Collins Stewart

Most of my questions on the Haynesville have been answered, but what – can you just talk about the takeaway capacity as it pertains to your growing production?

Gil Goodrich

Hi, Kim, this is Gil. We are – obviously this is an evolving situation. As we’ve said on prior calls and certainly others have said, one of the nice things about the Haynesville is it’s sitting within a very mature natural gas producing province. And we do not see any material impact on a short-term basis. I think the question really is probably a late ’09, ’10 event where if all of the capital that could get spent does get spent and the production rates end up being at the high end of the range. You may see some short-term bottlenecks. That being said, we have had independent meetings ourselves with people that have early stages for significant Bcf per day plus takeaway capacity from the Northwest Louisiana, East Texas area to get gas further east. So we remain pretty confident that while there may be some additional firm transport deals that we’ll strike over the next six months or so, ultimately the market is going to work itself out and we’re not going to see any major hiccups.

Kim Pacanovsky – Collins Stewart

Okay. And, Rob, you and I have talked about the issue of higher rates in some of those thinner zones before. Just from looking at your core data, what are you seeing in the core data that is controlling that? Is it just better permeabilities as you move further west even though you have the center section?

Rob Turnham

Well, we don’t see that. That’s the real head scratcher. We have very similar porosities and what we can determine is permeability. We’ve treated them very similarly. It may be a difference in vertical – vertical IPs that may not translate into a difference on horizontal. In fact, my guess is, the thicker you are, the better you are for a horizontal development. But we just know that. So again, we’re a bit in the dark. We don’t see any conclusive data that suggests that that one well or those two wells in our Minden area should have IP-ed at a higher rate than what we see in North Louisiana.

Kim Pacanovsky – Collins Stewart

Okay. And switching to the horizontal James Lime play, if South Cotton does work, how many locations do you have there that could potentially be added to the probable hospital category? And also, you have a fairly large range of IPs within Cotton. What is the average EUR that you are determining in the average cost now that you have several wells down?

Rob Turnham

Yes. We’ve all along on average cost side said that this is kind of a $4 million completed well cost. It depends on length of lateral. Sometimes you can drill them for cheaper. I think we have gone as low as $3.3 million or $3.4 million. But in general, if you are drilling the longer laterals, which do tend to work better, that’s a better number for $4 million. Our expectations for the play across the board have always been kind of the 2 to 2.5 Bcf reserve, and nothing tells us that we can’t achieve that over a big area. Some are going to be better and some are going to be worse, again statistical. As far as number of potential locations, if you remember or can turn to our inventory chart, where we’ve only captured about 50% of the James Lime potential of Angelina River. Of that 50%, 50% of that would be roughly Cotton South and the other 50% would be our Bethune, Allentown and East Lake acreage. So, another 50% of roughly 358 locations that would – I would probably say another 150 potential locations, but again –

Kim Pacanovsky – Collins Stewart

Okay. That’s substantial.

Rob Turnham

It is substantial. And again, the blend would be – maybe 25% of that acreage – maybe 30% of that acreage would be, Goodrich 100% ownership, and 70% of that would be – we would have a 40% ownership interest with EnCana.

Kim Pacanovsky – Collins Stewart

Okay. Okay, great. And just last question, you mentioned this West Esperanza well. Where is that? Is that in Cotton?

Rob Turnham

Yes, that’s another Cotton well in which we own a 57% working interest.

Kim Pacanovsky – Collins Stewart

Okay. All right. That’s all I have for now. Thanks guys. Congratulations again.

Operator

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

Richard Tullis – Capital One Southcoast

Hi, good morning.

Rob Turnham

Hi, Richard.

Richard Tullis – Capital One Southcoast

A lot has been covered already. I just had a few other things. Rob, what’s your average royalty rate across all your Haynesville exposed acreage?

Rob Turnham

Well, it varies. Let me give you – probably our blended average royalty at Bethany-Longstreet would be 29%. That’s a combination of – predominantly it’s a farm-out agreement that has a 30% burden and then we have some new leases that have a little bit less than that. If you go up to Longwood and Central Pine Island, that would be roughly 25% burdens. If you go to Beckville, that would be roughly 25% burdens. If you go to Minden, that’s about 23% burdens. All of this is to the 100% obviously. So you have to multiple that in terms of working interest. South Henderson is roughly, I would say, 24%. And down to the Angelina River trend, a blended average of about, I would say, 20% – maybe 21%.

Richard Tullis – Capital One Southcoast

Okay. Thank you. Any early outlook on the mid-year reserve numbers?

Rob Turnham

No. They do a top-to-bottom independent analysis of our reserves and we never do know until we get the final product as to where we stand. But obviously with production growing, 15% and 16% sequentially in the first two quarters, that means wells – we are doing very well on the wells that we’re drilling. So we’re optimistic that we’ll give a report that looks pretty good.

Richard Tullis – Capital One Southcoast

Okay. I know you gave your average rate for the second quarter. Can you give us what current production is right now net overall?

Rob Turnham

No, we never do that. We try to give the next quarter’s guidance, which certainly gives you an indication of where we think we’re headed. But it’s just a policy of ours to not talk about our current rate. It can fluctuate a good bit. What’s important is that you are seeing significant sequential growth quarter-over-quarter.

Richard Tullis – Capital One Southcoast

And looking at into ’09, what kind of early expectations do you have for growth in ’09?

Rob Turnham

Well, again, we give quarterly guidance and we are comfortable with that, mainly because we have such moving parts. And if we are on pace to have at least 50% growth in ’08 versus ’07, and frankly that’s just holding the low end of guidance over the second half of this year. And you start layering in Haynesville Shale horizontal wells that have a much bigger production profile, even though we have more wells that are declining that you have to outrun from a rate of return – return of growth standpoint? You’re clearly looking at something that should be similar if not greater. So we are not just prepared to step out and give that guidance.

Richard Tullis – Capital One Southcoast

Okay. And lastly, the Haynesville wells severance tax, will the severance tax exemption apply to these or do you expect they will be taxed at the normal rate.

Rob Turnham

Yes, East Texas, which is really where the severance tax relief is, the Haynesville, or it may be called the Bossier, we will have to see, but should qualify. I mean it is a shale that you would assume would be a tight gas sand type credit. In Louisiana we don’t have that. So, as to how many wells we drill in East Texas versus North Louisiana, then we’ll see. David may have something to add to that.

David Looney

Yes, Richard, just as a note. In Louisiana, you do get a horizontal credit. It’s a two-year severance tax credit there, which is obviously not nearly as attractive as the ten-year – up to ten years we get in Texas, but at least it is worth something.

Richard Tullis – Capital One Southcoast

Okay. That’s all for me. Thanks so much.

Rob Turnham

Thank you, Richard.

Operator

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

Dan McSpirit – BMO Capital Markets

Gentlemen, good morning.

Rob Turnham

Hi, Dan.

Dan McSpirit – BMO Capital Markets

Of the vertical wells that you’ve drilled to the Haynesville, have you been able to determine or confirm original gas in place for section estimates?

Rob Turnham

We have seen – this is Rob again. We have seen 180 Bcf per section estimates out there gas in place. And we certainly have done some work and that supports what those same numbers as to what we are seeing in 29%to 30% recovery factor. So we haven’t done core analysis on each of wells. We’ve really basically done more kind of log analysis and more advanced log analysis to go with that. I think we’re comfortable at least at this point in saying that what we have appears to be consistent, and we couldn’t argue with the gas in place and recovery factors.

Dan McSpirit – BMO Capital Markets

Perfect. That’s all I’ve got. Great outlook. Get at it.

Rob Turnham

Thanks, Dan.

Operator

Next question comes from the line of John Healy [ph] of Forest Investment Management.

John Healy – Forest Investment Management

Good morning, gentlemen. Great quarter.

Gil Goodrich

Thank you.

John Healy – Forest Investment Management

When you mentioned before that your borrowing base redetermination, what number did you think it was going to move to? 450 did you say?

David Looney

No, John, actually – this is David. Actually we said in my comments that the combination of our cash and short-term investments, plus our new borrowings will probably be around 450. Our borrowing base today is $175 million. In fact, over the last several quarters we’ve been averaging increases in the 35 million to 40 million range sort of per every six-month redetermination. So if you just assume a similar type of number and then look at the cash we have on hand, that’s where you get at a total liquidity number of about 450.

John Healy – Forest Investment Management

I see. Okay. And then the – I know you had paid off the revolver after the quarter. It was over with at Chesapeake and common equity offering proceeds. But what was the balance, was that $100 million at the end of the quarter?

David Looney

It was $96 million when we paid it off in early July. It was actually $81 million at the end of the quarter.

John Healy – Forest Investment Management

Okay, $81 million at the end of the quarter. Very good. And what was at the end of – just for like historical modeling purposes, what was the cash balance at the end of the quarter?

David Looney

At the end of the quarter, it was in the $5 million or $6 million range. Yes, almost right at $6 million.

John Healy – Forest Investment Management

Got you. And when you mentioned in your comments about – with your new very, very strong liquidity, not having to come back to raise capital for – can you repeat that again?

David Looney

Yes. We said, basically if you look at this liquidity that we have now and obviously with the growing cash flow and production profile, of course, all of that is hinged upon the sort of commodity prices we have as we said here today. We think we are in the late 2010, sometime in 2011 perhaps before we are going to be in some sort of a crunch, if you will.

John Healy – Forest Investment Management

Got you. Okay. Again, good quarter. Thanks for answering my questions.

Gil Goodrich

Thank you.

Operator

And you have no questions at this time. I will now turn the call back over to Gil Goodrich for closing remarks.

Gil Goodrich

Thank you very much. We appreciate everyone’s attendance this morning. We feel really good about the outlook going forward. We are excited about it. And we look forward to announcing third quarter numbers for you in a couple of months. Thank you.

Operator

Thank you for your participation in today’s conference. This concludes the presentation. And you may now disconnect.

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Source: Goodrich Petroleum Corporation Q2 2008 Earnings Call Transcript
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