Goodrich Petroleum Corporation
Q2 2014 Earnings Call Transcript

Published: 7 Aug 2014

[Operator:]

Good day, ladies and gentlemen, and welcome to the Q2 2014 Goodrich Petroleum Corporation Earnings Conference Call. My name is Sue, and I will be your operator for today. [Operator Instructions] As a reminder, this call is being recorded for replay purposes. I would like to turn the call over to Mr. Daniel Jenkins, Director of Investor Relations. Please proceed, sir.

[Daniel Jenkins:]

Good morning, everyone, and welcome to our second quarter earnings conference call. I would like to begin with the introduction of the management team on the call with us this morning

[Walter G. Goodrich:]

Thank you, Daniel. Good morning, everyone, and welcome to the second quarter call. The second quarter was somewhat impacted by a couple of nonoperational items, which Jan will review with you in more detail in a minute. But the quarter also began to illustrate some of the progress we are making in the Tuscaloosa Marine Shale. Oil production grew by 11% sequentially and was led by volume growth in the TMS, which accounted for approximately 40% of second quarter oil production, but more importantly, is expected to account greater than 50% of our oil production as we exit 2014. We are starting to see meaningful production growth in the TMS, and we expect this to continue through the third and fourth quarters of this year. Driven by TMS volume growth, we are projecting net oil production will grow sequentially in a range of approximately 15% to 25% in the third quarter compared to the second quarter's production. While the recent stock price performance may not recognize it, we and our partners in the TMS are making excellent progress in the delineation and defining of the play and doing so at a significantly faster pace. Among the 5 largest participants in the play, there are approximately 1 million acres under lease in the Eastern TMS, which extends over 100 miles east to west and approximately 45 miles north to south. This is a very large geographic area and will require many additional delineation wells to fully define the play. But as I said, we and our partners are making tremendous progress and beginning to define those areas of highest prospectivity. We now have approximately 44 modern-era horizontal wells drilled in the TMS in the past couple of years and currently have 12 additional wells in either drilling or completion phase. While still early, these 45 wells are beginning to give us some insight into the variability of well performance, normalized for early stage frac designs and mechanical issues, which may be influenced and driven by rock properties. In addition, the 44 wells now producing are significantly adding to and refining the type curves established and continuously updated for the TMS. Again while still very early, we currently believe wells with initial production rates in excess of approximately 700 barrels of oil per day and following the range of type curves we have developed internally and made public will ultimately be very economic wells at current commodity prices. This is particularly true in development mode, where we can significantly reduce individual well costs through multiwell pad drilling. And all recent wells have exceeded these production levels. In addition, we are beginning to see indications of incrementally better matrix permeability and increased fracture density as the principal driver behind the very strong initial performance from wells exhibiting initial rates in the 1,200 to 1,500 barrel per day range. We are also seeing a trend develop for wells with initial rates slightly less than 1,000 barrels a day of somewhat flatter decline profiles. This is possibly, if not likely, the result of slightly less natural fracture intensity in some areas but similar natural matrix porosity, which is generally consistent with the geologic data available to us. We are continuing with a very robust data gathering and analytical process to assist us with both forward development and delineation planning. We are particularly pleased with the additional industry activity in the play by our TMS partners. Their activity in particularly the last half dozen or so wells have meaningfully enhanced the play's delineation with wells exhibiting over 1,000 barrels per day of initial production. And we congratulate them on their results. Their results, with our data-sharing agreements in place, coupled with our activity, is allowing all of us to gradually tweak and refine our drilling and completion practices. And I believe it's helping all of us move closer and closer to best practices for the TMS. While clearly significant derisking and delineation drilling remains to be accomplished to fully define the 1 million acres currently under lease and we do not have enough completed wells and data to eliminate any acreage at this time, what we can say factually is that we now have wells along an east-west line between approximately 10,500 feet and 14,000 feet true vertical depth, which have yielded the most prolific results in the play and cover a very large portion of our current acreage position. Undoubtedly, we will likely see some variability within this overall area. But within this area, we can also drill down to a substantial area running from west of our Crosby well in Wilkinson County, Mississippi to southeast of our Blades well in Tangipahoa Parish, Louisiana and covers an area of approximately 60 miles by 20 miles, which has now consistently seen wells devoid of mechanical issues with initial potentials in excess of 1,000 barrels per day. Our most recently completed wells, including the Blades, Nunnery, Beech Grove and SLC wells, were classified internally as delineation wells or step-out locations necessary and designed to further define and delineate our extensive land position. While more work is yet to be done in this regard, the next series of wells, including the CMR/Foster Creek 31-22H-1, CMR/Foster Creek 24-13H-1, Spears 31-6H-1, all of which are currently drilling, and the next half dozen or so operated wells to be drilled, as well as the Denkmann 33-28 #2 well, which is in completion phase, are all fairly well defined within our fairway and considered developmental in nature. The only near-term exception is possibly our Bates 25-24H #1 well, which is situated just on the northern end of the fairway, and has the potential to extend the play slightly northward. As a result, we expect the next few months and through the end of the year will provide nice acceleration in our oil volume growth. Looking forward, we are continuing to look for opportunities to accelerate development of the TMS, particularly in the areas within the fairway, while also very carefully managing our balance sheet and liquidity. In that regard, we have recently initiated a soft process in the TMS, soliciting potential partners who share a similar view of the play and its tremendous potential. We are beginning to hold early phase discussions with a number of potential partners, who could assist us in the development and the acceleration of the TMS. Also, over the next 60 days, we will finalize our midyear reserve review at redetermined borrowing base under our senior credit facility. In addition, we are actively evaluating divestiture options for one or more noncore assets designed to ensure we have ample liquidity to execute our strategy. And with that, I will now turn the call over to Rob Turnham for more details and an update on the quarter.

[Robert C. Turnham:]

Thanks, Gil. We reported initial production results on 3 new TMS wells for the quarter with a blended average 24-hour rate of 1,233 BOE per day with over 93% oil cut. We also reported a 30-day rate on our Beech Grove well that had been previously reported, which had a flatter initial decline as currently on our 600,000 barrel equivalent type curve. Our SLC well had at 24-hour peak rate of 900 BOE per day on a 12/64 choke and is exhibiting similar initial characteristics of our Beech Grove wells. And we will update those results along with all of our wells and our decline curves in our management presentation. As Gil stated, we now have wells from approximately 10,500 feet to 14,000 feet true vertical depths, which depths cover approximately 90% of our acreage block. Approximately 2/3 of our block sits between 11,000 to 13,000 feet, which are the depths that we have seen the best wells drilled to date as to initial rates. That said, and as Gil stated earlier, the variability we have seen to date has primarily come from the initial 45 days of production, likely due to less naturally occurring fractures, which typically provide high initial rates but exhibit steep initial declines. It is still early, but the matrix of the rock throughout the areas in which we have drilled wells appears to be producing very well and similarly, which is the most important aspect for long life reserves. We are developing a very good database of consistent well results exhibiting similar-shaped hyperbolic curves. We have a vertical well in the TMS that has produced for over 30 years, 3 short lateral wells drilled in the field by another operator that have been online now for 5 to 6 years as well as more optimized, newer vintage wells that have produced for 18 to 26 months, all of which have similar-shaped curves, even though the newer vintage wells have much higher production rates. This gives us confidence that the matrix of the rock will perform over a long time, consistent with other resource plays. We also see a good correlation in results with proppant per lateral foot from hybrid frac jobs and feel our completion recipe is working very well. And we are seeing other operators complete wells similarly. We are currently running 3 rigs in the play, with plans to accelerate once we bring in a partner or raise additional capital from a noncore asset sale. Now that the initial delineation phase is behind us, going forward you will see the vast majority of wells drilled in the proven fairway with 4 wells expected to be completed and reported by the end of September. In the Eagle Ford, we added 3 gross, 2 net wells in the quarter with 3 gross, 2 net wells in the completion phase. In the quarter, we had capital expenditures of $106.5 million, of which $89.9 million was spent on drilling and completion costs, $13.2 million on leasehold acquisition and extensions and $3.4 million on facilities, capital workovers and other miscellaneous expenditures. Approximately 70% of expenditures were in the TMS. CapEx for 6 months ended June 30 was $162.3 million. And we are on pace to come in at the low end of our CapEx budget, unless we accelerate development in the TMS, which again is dependent on incremental capital. Production for the quarter totaled 6.2 Bcf equivalent or an average of 68.6 million cubic feet with oil comprising 37% of volumes and 72% of revenues. Oil volume growth was back end-loaded during the quarter and will further accelerate in the third quarter through the end of the year. In closing, we maintain an acreage block in excess of 300,000 net acres in the TMS, which will provide us tremendous running room in a pure oil play with superior economic returns. With that, I will turn it over to Jan 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 $53.3 million, an increase of $4.8 million or 10% over revenue for the comparable period last year and $1.5 million or 2% higher than revenue for the second quarter of 2014. Our second quarter average realized prices, excluding the impact of realized gains on derivatives, were $100.48 per barrel for oil and $3.78 per Mcf for natural gas. Natural gas price realizations for the quarter were low as non-operated gas price realizations declined. Our non-operated gas price for the second quarter came in at $2.54 per Mcf. The non-operated gas price is net of transportation and marketing fees. Our operated gas price for the second quarter was $5.04. Note that 50% of our natural gas production for the second quarter comes from properties operated by others. For the balance of 2014, we have a total of 3,800 barrels of oil per day hedged at a blended price $93.65 and 30,000 MMBtu per day of gas hedged at a blended price of $4.76. We also layered on additional 2015 oil hedges, bringing our total to 3,500 barrels of oil per day, hedged at a blended price of $96.11 for 2015. Our plan is to continue to layer on additional oil derivatives as we continue to increase oil production. We also continue to watch natural gas for additional opportunities to hedge portions of our natural gas production. Please see our website later today for a slide of our current derivatives positions. Moving on to expenses. LOE per Mcfe this quarter was $7.3 million or $1.17 per Mcfe compared to $1.33 last quarter and $0.88 for the prior year quarter. The second quarter includes $1.4 million or $0.22 for workovers primarily in the Eagle Ford Shale. As we have mentioned before, as we increase our oil production, we would expect our LOE rate per unit to gradually increase over time with oil production representing 37% of total production in the second quarter, as Rob earlier stated. DD&A per Mcfe was $4.82 per Mcfe for the quarter compared to $4.51 last quarter and $5.18 for the prior year quarter. We would expect the overall company DD&A rate to trend slightly higher next quarter as oil production continues to increase as a percent of total production. G&A costs came in at $9.5 million, $1.51 per Mcfe this quarter compared to $1.38 last quarter and $1.15 in the prior year quarter, due to higher compensation expense and stock-based compensation. About $0.37 or 24% of the second quarter rate represents noncash stock-based compensation. Other expense of $3.4 million includes a $2 point million -- $2.8 million charge for gathering and marketing costs on our non-operated Haynesville wells. We are currently disputing this charge with the operator of the wells. Also included is a $0.6 million charge for a long-standing working interest dispute on a property we no longer own. We are projecting a 0 tax rate for the full year of 2014. We ended the quarter with $0.5 million in cash and $48 million drawn on the revolver. Our current borrowing base is set at $250 million under our senior credit facility. As Gil mentioned, the next redetermination of our borrowing base will occur in October of 2014 based on our midyear reserve report, which should benefit from TMS well results in the first half of 2014. 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 2014 10-Q with the SEC later today. Please see our 10-Q for a more detailed financial discussion. With that, I will now turn it back to Gil for some closing comments.

[Walter G. Goodrich:]

Thank you, Jan. As I said on our last quarterly call, challenges remain in the TMS and we do not expect every well to be drilled faster than the previous well or to outperform the last well's production. But we do expect and are seeing a gradual trend of wells being drilled quicker with fewer problems and for less overall cost. We expect this trend to continue and are preparing for the transition into development multiwell pad drilling, which should significantly improve total completed well costs and significantly enhance economic returns in the play. In short, while there have been and undoubtedly will be bumps along the road, the TMS future looks very bright and we remain tremendously excited about the play. While we simultaneously develop the TMS and preserve our extensive gas assets waiting for a better natural gas market, we believe shareholders who share our belief in the vast potential of the TMS, as our board and senior management does, will be rewarded over time. And with that, I'll turn it back to Sue for questions.

[Operator:]

[Operator Instructions] Your first question comes from Phillips Johnston, Capital One.

[Phillips Johnston:]

You referenced it in the prepared remarks. But is there any more color that you can give us on your current thinking in the progress around the joint venture process and how it might be structured? And just as a follow-up to that, how do you weigh that option versus an outright equity offering or some structured preferred transaction, like one of your peers has executed in the play?

[Walter G. Goodrich:]

Sure, Phillips. Rob, either one of us could take that, but why don't you take it?

[Robert C. Turnham:]

Yes, Phillips. I think our preference at the top of the list would be to bring in a partner, do a JV on the TMS, versus a noncore asset sale and certainly have no interest in equity at these prices. Obviously, we would prefer a cash-and-carry type structure, more traditional JV would be at the top of our list. But we won't rule out any other type of financing, it's just certainly not our preferable structure. So as Gil stated, we're continuing to have some discussions. We've had quite a bit of interest of late, and we'll continue down that path. But that would be our preference.

[Phillips Johnston:]

Okay. And just on the 5 TMS wells that are currently in progress, have you seen any issues or any delays with any of those 5?

[Walter G. Goodrich:]

Yes. I'll take that, Phillips. Basically, everything is on track. We did have a little issue on our CMR/Foster Creek 31. We are back to drilling on that well. There were some rumors floating around earlier this week. Clearly we're going to run a little bit over on time and probably dollars on that. Too early to say exactly how much, but we are back to drilling. Other than that, we're making great progress on our other CMR 31 well. I think I said 31, I meant 24, excuse me, the 24. The CMR/Foster Creek 31 is going extremely well, nearing TD on that well and making great progress on our Spears. So I think that's probably all from an operational standpoint on the drilling wells.

[Phillips Johnston:]

Okay. And just last question, can you say what the completed well cost has been for your last 3 operated wells or at least how they've compared to the AFEs?

[Walter G. Goodrich:]

Yes. Rob, do you want to take that?

[Robert C. Turnham:]

Yes, Phillips. We don't give specific well cost per well. I will point you to our management presentation. We're still very comfortable with our kind of one-off type curve wells, AFE at $13 million. We do think by the end of this year and as we move towards 2-well development wells off of pads that you could see that transition into kind of more of a $11.5 million range. And obviously, again in our presentation, you'll see full development mode. We think we can ultimately get to $10 million. That obviously depends on lateral length as you -- if we continue to stretch these laterals out. We saw a really good result from Encana on the Lewis well that was north of 8,000 foot lateral. No question, at least early days, that, that's likely the best well drilled to date. And if we start extending these laterals out, then obviously we'll have to adjust those costs. But we would just point you to that. As Gil said, you'll have some that will be above and some will be below it. But the general trend is trending in the right direction. And now that the initial phase of delineation is behind us, you're going to start to see us execute on some 2-well pads at least, such as our Spears well, which is drilling right now. It's off of the Lewis pad. It's a southern down zip lateral off of the existing Goodrich Lewis pad. So with that, you'll see us drive cost down and obviously reducing drilling days with amortization of facilities over multiple wells. And then coming behind that with zipper fracs is going to drive the cost down further.

[Operator:]

And your next question comes from Leo Mariani, RBC.

[Leo P. Mariani:]

Just want to follow up on some of these kind of asset monetization options here. You mentioned 1 or 2 noncore asset sales as potential. What would those assets be that you're looking to potentially sell here?

[Walter G. Goodrich:]

Yes, Leo, this is Gil. So nothing surprising here, East Texas, Cotton Valley, has kind of perennially been on our list. That's certainly one of the things that we're considering. As Rob said, that would not be our preference, but we certainly want to make sure we've got ample liquidity, as I've said in my remarks. So I think that's at least one of the areas that we'd be looking at. And then longer term, some other assets will come into play that we're probably not quite ready to talk about.

[Leo P. Mariani:]

Okay. And I guess, just in terms of JV, is that something you guys hopefully have wrapped up kind of by the end of the year? How should we think about timing on that?

[Walter G. Goodrich:]

Yes. On the JV, sure. As Rob said, we're making pretty good progress. We have begun talking with folks, hard to predict exactly. We're running a soft process, we're not setting any firm dates out there. We're much more interested in finding the right partner with the right similar mindset and the right structure and obviously value. So we would certainly hope that by the end of the year, we certainly have found a partner, if not consummated the transaction. It could happen sooner than that, but that's a fair timeframe, next few months.

[Leo P. Mariani:]

Okay. And I guess, just in terms of adding the fourth and fifth rigs in the play, I mean, based on all that, I mean, should we assume that's more of a 2015 event as opposed to 2014?

[Walter G. Goodrich:]

Well, I think as Rob said, it's a function of finding the right partner, bringing in some incremental capital, whether that's through an asset sale or it's through a JV. I think you'll see us step up more than likely at the point at which some incremental capital has come in.

[Leo P. Mariani:]

Okay. And I guess, just looking at some of your latest wells, a question was asked on well cost. And I guess, obviously you guys are sticking with your AFE. Can you talk to drilling times on some of the latest TMS wells in terms of what you've seen?

[Walter G. Goodrich:]

Leo, I would just recite what I just said a minute ago, which is some of the wells are coming in above, some are coming in below. If you'll remember, we started with a 45-day curve. We had a couple of wells that run a little beyond that. We've also had a number of wells now that have come in less than that. And the overall trend, we think, is moving in the right direction. So we've seen some sub-30-day wells, we're not ready to start marking up all future wells as sub-30-day wells. But if we can start to move that into the 35- to 40-day range by the end of the year consistently, that'd be great progress.

[Robert C. Turnham:]

Yes. And Leo, I might add, every time you step out and drill in a different area, there are some particular aspects to that, that might be slightly different. And obviously, we've done that on the Beech Grove and the SLC. Now that we're moving kind of back into the fairway, where we have direct experience drilling wells in that area, we feel very good that, that's going to create an opportunity to really drive those drilling days down. Now with that being said, a good problem to have in some of these areas is just, if you encounter these natural fractures, you have to fight it, the well from flowing on you. And we've seen some of that in some of these areas, like the Foster Creek, frankly, the Bates well had some similar aspects to that. So fractures are your friend on production, but when drilling through them, sometimes that can add some days as you fight through the well flowing on you. So as Gil said, every well is different. But the more experience you have in a particular area, the more confidence you have that you'll get those wells down and drill them much quicker.

[Walter G. Goodrich:]

And I might add, the real issue is where the costs come in on development mode. Because as I said on the call last week or last quarter, we didn't buy the acreage addition we have to go drill several thousand one-off, single-well pad wells. So it's really where can we get to in development mode that matters.

[Leo P. Mariani:]

Okay. And I guess, in the TMS, what are you guys seeing for lease operating expense just in that particular play?

[Walter G. Goodrich:]

We're still running -- we're kind of modeling $1.25 per Mcf equivalent, Leo. Our numbers have actually come in a little less than that. So I think and hope that certainly as we move into some pad drilling, you're going to see those numbers come down even more and we can leverage multiple wells off a single pad in central production facilities. But right now, if you're modeling it, I would suggest you $1.25 in Mcf equivalent.

[Operator:]

And your next question comes from Neal Dingmann, SunTrust.

[Neal Dingmann:]

Rob or Gil, wondering, the first question just on the acreage. Obviously, between the newer Devon acreage you had picked up and your other, do you still feel pretty comfortable as you look at it from a west to east basis, you certainly had some solid wells down in the east and as well as up in the west area, I'm just trying to get a sense of if you're looking at that acreage any differently or more kind of as blanket still at this point.

[Walter G. Goodrich:]

Yes, Neal, this is Gil. I was trying in my prepared remarks to give as much color as we felt comfortable giving at this point. There's certainly areas that are now shaping up to be more core in nature. But the fact of the matter, we just don't have enough data to really tell us that anything is necessarily noncore. Clearly, our Beech Grove and SLC wells didn't have quite as high of an IP. But what we've seen, as Rob mentioned, is significantly flatter decline through the early performance. So that may just be, as I said, a function of maybe not quite as many natural-occurring fractures and density of those fractures. But as the geology suggests, fairly consistent matrix porosity and permeability in those wells, albeit giving up a little bit of early time production, may ultimately be quite good and we would suspect are going to be quite good over time. And so yes, I'd say that just close-ology suggests you get into a fairway there running east-west through Southern Mississippi and into southeast -- into the Louisiana portion. But it's too early to start ruling anything out. Hopefully, that helps.

[Neal Dingmann:]

It does. And then again you guys certainly made a lot of advancement on the drilling side as far as the number of days taken. Your thoughts as far as besides the drilling, just on the frac-ing, and then obviously when drilling out the plugs, I guess, 2 questions there. One, are you pretty confident on the frac technique that you're using? And then on when you're drilling out the plugs, going forward, will you now use mostly coiled tubing? Or how are you looking at sort of the frac end of the drill-out completions?

[Walter G. Goodrich:]

Sure. Rob, do you want to take that?

[Robert C. Turnham:]

Yes, Neal, really pleased with the frac recipe. We've kind of gone to a little more proppant. We're currently pumping about 550,000 pounds of proppant per stage. We're fluctuating between 250-feet and 270-foot frac intervals. Certainly, the Blades, at 250 feet, you would argue per lateral length was the most prolific of any of the wells. But we've seen some wells of late from other operators, where they pump the same amount of proppant or similar amounts of proppant but widen that spacing just a bit and seemed to have similar results. So I think we've really tweaked and zeroed in on a recipe that's working extremely well. And I think it's getting pretty consistently used by many of the operators. Your second part of your question was, remind me.

[Neal Dingmann:]

On the coiled tubing.

[Robert C. Turnham:]

The coiled tubing. Yes, anytime we've landed a lateral in the lower target, where obviously the quartz is higher and the clay is lower, we've yet to see an issue in drilling out the frac plugs, mainly because the casing appears to be stationary. We're not seeing deformation of casing. And therefore, we're able to get in, get the frac plugs drilled out. And we've gone back to -- several wells ago, we went back to a little bit larger coiled tubing unit, and we had no issues on these recent wells and getting the frac plugs drilled out. In fact, probably more efficient, certainly quicker and cheaper to do that. So yes, we've gotten -- developed a lot of confidence in being able to get the frac plugs out with the coiled tubing. And that's obviously creating a good bit of savings for us.

[Neal Dingmann:]

Absolutely. And then last question, if I could, for you all. I know you mentioned in the press release that the Beech Grove seems to be trending on that 600,000 type curve. Looking at some of the other prior wells, maybe going all the way back to the Crosby, are most of these wells still trending on the type curve?

[Walter G. Goodrich:]

Yes, I'll take that, Neal. To be clear, what we said is that the Beech Grove, while starting lower from an initial production rate, has now intersected within the first 30 days the 600,000 barrel curve. So it's kind of got an odd but much flatter shape to it and it's now out there tagging up with the 600,000 barrel curve. So we're just going to have to watch that over time and see how it ultimately performs. Other than that, yes, we update our curves internally weekly, and we're updating those every time we put out a new management presentation, which I guess is probably happening at least monthly. So everything you'll see, I think we're going to post one, what, this afternoon, Daniel? Yes, we'll post one this week, Neal, which will have everything updated through -- at least through last Friday.

[Operator:]

And your next question comes from Steve Berman, Canaccord.

[Stephen F. Berman:]

The 550,000 rate on the Beech Grove was after how many days?

[Walter G. Goodrich:]

Steve, this is Gil. We're out at about 45 -- between 45 to 50 days. I don't have the exact days but a little over 1.5 months online doing quite well.

[Stephen F. Berman:]

Okay. And Neal referred to the Crosby well. Do you have an update for -- that's been on, what, 15, 16 months now? Do you have an update on what that well was cum-ed or any other wells that have...

[Walter G. Goodrich:]

Yes. Steve, it's in our management presentation. That's going to be pretty good. And as I've just said, we'll have another one up sometime the next week. I don't remember the exact number. I guess I could look it up.

[Robert C. Turnham:]

I think we're in the 180,000 barrel range. It's a little bit longer than you state. I think it's 17, 18 months now, Steve.

[Walter G. Goodrich:]

Yes, that's right. A little over 180,000 barrels, Steve.

[Stephen F. Berman:]

Okay. And then just one more. Is there any formal process underway for noncore asset sales, is it in data rooms or anything like that or you're not quite at that point yet?

[Walter G. Goodrich:]

Currently handling everything internally.

[Stephen F. Berman:]

Internally. Got it.

[Operator:]

And your next question comes from David Deckelbaum, KeyBanc.

[David Deckelbaum:]

Just, Gil, in your prepared remarks, you discussed how much you think the industry has been delineating the play. Can you give -- do you have a broad estimate of how much of the play you think has been derisked across your aerial extent now maybe in percentage terms?

[Walter G. Goodrich:]

Wow, I would say -- and Rob, you may want to chime in here. But I would say that we're well over 125,000 net acres and maybe pushing over 150,000 net GDP acres that we think would be within kind of the core of the core as the play currently looks. And as I said in my prepared remarks, plenty of work to be done to further step out and delineate. And some of these recent wells that we've drilled, including the Beech Grove and the SLC, with performance over time could obviously extend that number pretty meaningfully.

[Robert C. Turnham:]

David, this is Rob. I think it is about half. And I think that makes sense when you kind of encircle the wells, and then count your net acres included in that halo.

[David Deckelbaum:]

Okay. And you guys had talked about this window of depths, between 11,000 and 13,000 feet. In the Beech Grove and the SLC and other wells that have been drilled below 13,000 feet, are you consistently seeing a lack of natural fractures at those depths?

[Walter G. Goodrich:]

That's a good question. Those are 2 deepest wells we've drilled, David. We would certainly look at both those wells and say they probably don't have quite as much natural fracturing. That's a little bit nebulous in terms of simply just looking at the way the well is drilled, you can't necessarily tell much from them the way they flow back other than it's becoming a little bit clearer to us that these 1,200 to 1,500 barrel a day wells in terms of initial rates are being juiced a bit with natural fractures. I'm not ready to completely go to the bank on that, but that's what it appears. And it dovetails with the geologic data, which was suggesting very, very little nuanced differences in rock properties, really across a very, very broad area, including the area around our Beech Grove and SLC wells. So whether or not that is something that continues with depth or is driven by depth is really an open question in our mind.

[David Deckelbaum:]

Okay. And then 1 more if I might. Just you did mention in the press release that you thought you'd be at the lower end of your $325 million to $375 million CapEx budget. And does that assume sort of no incremental rigs in the TMS, and that's what's fueling that? And then I guess, it sounds like you would not consider increasing the rig count in the TMS until you have a liquidity event of some case, either a JV or noncore asset sales. But if you marry that back to your earlier comments of how much you think you've derisked, 150,000 acres is still quite large. Are you also still thinking of scenarios of perhaps staying in this 3- to 4-rig program over multiple years and perhaps not retaining a 300,000 plus net acre position? Or how are you guys thinking about that?

[Walter G. Goodrich:]

Rob, do you want to take a first stab? I might chime in on that.

[Robert C. Turnham:]

Yes. And David, I think once we have a firm commitment and we know the capital is coming in, and as Gil stated, that could be as soon as a few months, certainly have that by the end of the year, then that gives you the confidence to go ahead and arrange for a fourth rig, let the funds come in, you could ramp to 5 rigs, as we've previously stated. There is an argument that you could, over time, high-grade the acreage, in fact, keep most of the interest in the high-graded acreage because 150 -- even 150,000 net acres is obviously a huge block for a company of our size. But as Gil stated, we're really not -- we haven't ruled out any of the acreage as to prospectivity. Over time, I think you'll see us gradually kind of expand the core. Other operators are going to be doing that for us. If you look at -- and we have great operators that are joining us in this development, obviously data exchange agreements with everyone. And if you look at where they're going to be drilling wells, they're going to help prove up additional acreage for us. So we're not going to have to carry the load exclusively ourselves. And I think if we focus, as we've said in our prepared remarks, in the fairway, continue to drill wells for the rest of this year, where we already have offset experience and results while others continue to kind of develop their block, we'll wake up by the end of this year and have a much bigger position derisked than what we currently have. So kind of a roundabout answer, but at this point, we want to maintain our block. We feel that the best source of capital is likely a JV. We do have alternate sources, but that would allow us to maintain our block as is.

[David Deckelbaum:]

Great. But all of the fairway drilling this year would be the identical completion design on the wells that you've used recently, staying in the same zone in the TMS and sort of conforming to that 6,500 foot lateral or so?

[Robert C. Turnham:]

That's right. We're targeting at a minimum 6,000 foot laterals. Sometimes you have to make a decision to stop short for various reasons. But certainly, at this point, that's our target and very, very happy with the completion recipe and the results we're seeing from that frac design.

[Operator:]

And your next question comes from Mike Scialla, Stifel.

[Michael S. Scialla:]

It sounds like your, I think natural fracturing may be the key to the higher rates. Is there any way to -- and think you kind of addressed this on previous question, but maybe coming at it a little bit differently, is there any way to map that? Can you see it on seismic? Do you see any relationship between fracture intensity and structures in the area or anything like that?

[Walter G. Goodrich:]

Mike. This is Gil. Short answer, difficult. We have not talked about it this morning, we probably will be talking about in the next call, but we have been working with Schlumberger to run some logs that are going to help us with that. Very early in that analysis, but fairly promising. We have, as have our partners in the play, been doing some work around natural fracture identification. A little bit difficult. I would say, internally, at Goodrich, we think it's not clear and definitive. There are some 3Ds that are in the early phase of planning. Whether or not those are going to have the kind of resolution necessary to see very small natural fractures, we do believe natural the fractures are fairly frequent in occurrence in 1.5 to 2 feet -- 1 every 1.5 to 2 feet, is what it looks like across the play from the data we have today. It looks like they're fairly vertical in nature and contained within -- or largely, I should say, contained within the TMS section. So whether or not that's something that's going to show up on 3D or not is an open question, and I at least one I'm little doubtful that it will. So I think it's going to largely be trial and error, plus taking through logs, whatever data we can gather and build a frac model over time. Hopefully that's helpful.

[Michael S. Scialla:]

That is, yes. And then I know in the past you've published a net pay isopach map. Can you say what you think, is that still an important variable? And can you say how you see that vary between some of the wells like the Beech Grove and SLC down in the southwest versus what you're seeing in the fairway?

[Robert C. Turnham:]

Yes, I guess, we -- yes is the answer. We do think that it's important. Where exactly the thickness or thinness cutoff is, you might look at our Nunnery well, which is up in the Northeast corner, a little thinner than most of the other wells, and it obviously, from an IP standpoint, at least fell a little bit short. Perhaps that could be due to thickness. That's fine, that's off the very northeast corner. Everything else is substantially thick. We're substantially thick running through our Beech Grove and SLC areas, so clearly we have plenty of thickness in those areas. And I think it really comes back, as we said in our prepared remarks, to the combination of what is the ultimate natural matrix, porosity and permeability, coupled with the areas where we see more are larger natural-occurring fractures. And so to a degree that's going to be trial and error, but we're starting to get enough data with the industry activity that's out there that as I said few minutes ago we're starting to draw a bull's eye around those area or areas that we consider more core in nature, and just take our time developing the rest of it.

[Walter G. Goodrich:]

Yes, Mike, let me add 1 thing to that. When we're overlaying porosity with resistivity, kind of this passing method which is an attempt to kind of develop a net pay thickness of quality rock. And the thickness, likely has a bigger bearing on EUR. And the more thickness you have of high quality rock, that is basically predicated on matrix performance, we think over time, would make a difference, certainly versus IP. Everyone's kind of infatuated with the initial rates. But again, we think that's more driven by naturally occurring fractures.

[Michael S. Scialla:]

That's helpful. I appreciate that. And then last one for me. You kind of addressed this already too, but you're shifting back toward the -- what looks like the fairway right now for the remainder of this year. As you look into next year, how do you balance drilling delineation wells versus saving acreage? What kind of time pressures do you have in terms of saving acreage? And do you need a partnership in place before you start looking to do some more step-out drilling?

[Walter G. Goodrich:]

Yes, I think it makes sense. I mean one of the things, following up on David Deckelbaum's question, Mike, is that we're going to approach it from a very prudent standpoint. We're going to marry up balance sheet and liquidity with desire and necessity to increase. Clearly we would like to see some incremental capital come in. We think that's prudent before we step up. So I think the next iteration, if you will, or handful of step-out wells, likely comes in 2015, with a focus kind of within that core from here, going forward. To the larger question, I think the acreage as we said on the call last quarter is in pretty good shape until we get to the end of next year. We spent a good bit of capital in this quarter, paying extensions and bolstering our position so we're now quite a bit above 300,000 acres. So we're building ourselves some nice cushion there in case we decide not to try to renew or preserve acreage late next year. But we're still circling around a plan forward that if everything comes together holds -- continues to hold 300,000 net acres, and we'll work through that as time dictates.

[Operator:]

And your next question comes from Dan McSpirit, BMO Capital Markets.

[Dan McSpirit:]

Question is on the natural fracturing. Do other operators in the TMS agree with your assessment on natural fracturing? Or is another explanation offered on the observed differences in the early rates and maybe with it, the potential to see higher early rates on wells drilled at depths closer to 14,000 feet? Just asking in an effort to get a handle on how the fairway acreage amount could increase over time.

[Walter G. Goodrich:]

Yes, I'll take at least first part of that, Dan. I would probably direct you to them for their take on exactly what the contribution of natural fracturing is. Secondly, hopefully, what we've come across with this morning is we think that -- I think in my prepared remarks, I said possibly, if not likely. So we're certainly not of an absolute 100% firm conviction that, that is the driver. But as we look at the geologic data available to us and we see the way some of these wells are drilling, we see some of these juiced initial rates, it just appears that either you have significantly better matrix permeability, which is driving those higher rates, or it's got more natural fracturing. And as we look at the geologic data, we just don't see anything that's pounding us over the head suggesting they got better matrix porosity. And that, as you know, has been kind of a core theme to us from the beginning of our entry into the play through the Devon acquisition, and really is unchanged today. So we're heading in that direction, to that conclusion. I don't think we're 100% there yet. And as to the others, I think they certainly recognize it as a possibility, but we would point you to them for color on what they really think.

[Dan McSpirit:]

Okay, understand. Is the same natural fracturing or maybe lack thereof similar in the TMS zone, above the rubble zone, as observed in the lower target?

[Walter G. Goodrich:]

It appears to be, yes. And we're getting this occurrence of the fractures, Dan, from both the dozen or so conventional cores that have been taken that we see natural fracturing and we see that occurrence. And Devon did a very extensive frac study, taking all of that data and it looked like about one natural fracture occurring every roughly 1.5 feet along a lateral. And as I mentioned, we've recently run a log in conjunction with Schlumberger that's confirming something fairly consistent with that. So that's the basis of our analysis.

[Dan McSpirit:]

Got it. Okay. And then just turning to the JV process. Do you have an implied price per acre in mind that needs to be hit in order to strike a deal? And if so, what is that amount?

[Walter G. Goodrich:]

Yes. Rob, do you want to take that?

[Robert C. Turnham:]

Yes, Dan. Kind of depends, if you're looking at the total block, which include some areas that doesn't have any well control on it or at least wells that have been drilled, we have ample well control throughout the whole block, which is why we're comfortable that all of our block could be prospective. We've stated this before that if you're looking at buying a percent of that, it's minimum 5,000 acres, basically our target. But if you start zeroing in on kind of the fairway or areas, and you start diminishing the number of acres, then obviously that number goes up. So we haven't put exactly what we would take if you come through with an alternative offer. But the 5,000 acre is still a good number. But that would include all of our block and equally distributing risk and acquisition.

[Dan McSpirit:]

Great. And then 1 last one, on the subject of well costs. Given the vertical depth of the TMS wells, is there maybe a physical limit to cost reductions? That is, can you lower cost only so much given the depth and pressure involved? And if so, what is that mark? I'm just asking for modeling purposes here.

[Walter G. Goodrich:]

Rob, I'll take the first piece, you take the second piece. Depth really is not a huge driver, Dan, because what you're talking about is whether it's 1,000 or 2,000 additional feet, that's all in the vertical portion, and we can chew that up pretty quick in a couple days of drilling time. So the bigger question you hit on it, is in the additional depths and therefore, bottom hole pressure takes a little more horsepower, a little more pump pressure to get it to break and to get our fracs away. Hard to say exactly, long term, what increment that is. It's not a tremendously higher expense. So we don't see anything that would tell us that any portion of the play is going to be materially, more or less, expensive. It really comes back to how quickly you can get the wells down.

[Robert C. Turnham:]

Yes, and I'll add to that, Dan, SLC obviously at 14,000 feet, well 90% of our acreage sits at or more shallow than 14,000 feet. So I would echo what Gil said. I mean, I think we get the wells down fairly quickly. It does require a little bit more horsepower. But that's on the incremental cost, that's not really a huge number. It's all going to depend on getting the well drilled as fast as possible and then moving into pad drilling as quickly as possible.

[Operator:]

And your next question comes from Ron Mills, Johnson Rice.

[Ronald E. Mills:]

A couple of follow-ups just from other questions associated with the completion design comments. Maybe, Rob, for you. Can you talk about maybe flowback differences, the SLC smaller choke than both the Lewis and Mathis reported, and I think a smaller choke than some of your prior wells. Is there anything driving that or how is the flowback process evolving from an industry standpoint?

[Robert C. Turnham:]

Sure. Well, Ron, we're seeing really nice evidence of benefit if you'd be a little bit more conservative in the early flowback on your chokes. It's not just us, we've seen some operators doing it as well. And when you think about it, we're in an over pressured oil reservoir that wants to surge if you open the choke, it'll push the fluids through the formation at a fairly fast pace and therefore, increase the odds of closure or crushing. And so we see real benefits in certainly early time, conservative choke management and the SLC, being the deepest well that we've drilled so far, and you're looking at a pressure gradient just say of 0.7 PSI per foot. So you're looking at almost 10,000 pounds of bottom hole pressure. And we felt that it was much more prudent to kind of be conservative and keep -- at least make your choke adjustments over time in a very orderly, conservative manner. And we wouldn't be surprised to see other operators kind of following that suit.

[Ronald E. Mills:]

Okay. And did you say on the completion side, that you're now kind of plus or minus that 550,000 pounds of proppant, so you increased that a little bit over the last 3 to 6 months. Is that where you and the other guys are really starting to hone in, in terms of maximum cost versus benefit or...

[Robert C. Turnham:]

Yes, if you do -- if you go ahead and do linear regression on EUR per foot, and you look at proppant per foot, as to where your projections take you, you can see a real nice correlation there. Now you can put too much proppant if the fluids are too high, you're going to have to -- you're going to struggle, and we've seen that from some other operators. But as long you're doing the hybrid frac, and we believe in the hybrid, you start with that slick water pad to create the fracture complexity, then introduce the gels to transport the proppant out into the formation, and we're very comfortable and very happy, currently with the 550,000 pounds. We think that so far is making the best wells, as long as you do the right spacing and have a hybrid job.

[Ronald E. Mills:]

And the SLC is, because what you just mentioned, it's the deepest well, although the oil cuts in yours and really everyone's wells have been remarkably consistent. Is there a little bit of a surprise that the SLC wasn't more gassy? Or does it look like, when you look at your acreage position, that from maybe a thermal or maturity standpoint, or whatever that it -- you may not have much of a gas phase?

[Walter G. Goodrich:]

Yes, Ron, I'll take that. Ron, we really have not seen anything yet suggesting a gas phase to this play. The only slight caveat would be the Devon lane well which is a vertical pilot only, did take a conventional core. The RO calculation in that core would be slightly higher thermal maturity. So I guess theoretically if you drilled a well down there, you might see a little bit more gas in the system. I am very doubtful that you would not still be way up in the high percentage of black crude oil coming from that well. And again, that well would be the deepest well in the very, very southern end of our block and the play. So it looks like the entire play to us is going to be way up there in the high percentages of black crude oil.

[Ronald E. Mills:]

Okay. And I think you both talked about plus or minus half of your 300,000 acreage being more core acreage. Based on the data so far, if we -- how would you break that 150,000 out versus the legacy Goodrich acreage versus the Devon acreage that you added last year?

[Walter G. Goodrich:]

Yes, I'll take that, Ron. So I think as I said in my remarks, if you went out there, just a little bit west, southwest of the Crosby well in Wilkinson County and you drew a line heading east southeast, and went through our Blades well and kind of drew a long, hotdog shape or football-type shape, you would basically circle around the acreage position that would get us up around 150,000 net acres.

[Ronald E. Mills:]

Okay. And then...

[Walter G. Goodrich:]

At this point, that's probably the best we can do.

[Ronald E. Mills:]

Perfect. And then hopefully lastly. You talked about the, I guess it's the Bates well probably in the last of the more delineation-style wells and more of your activity will be more in development mode. Is that sticking to your original plan? Were you potentially going to drill a well to step out to that last westward extension towards closer to the old Devon Murphy well? Or is that something that may be more of a 2015 event?

[Walter G. Goodrich:]

Yes. I think that we do have a well planned over there, which would be kind of west, northwest of the SLC. I think that well probably is getting into early 2015. I don't have the drilling schedule right in front of me. I think that -- we won't spud that well, Ron, until sometime early next year.

[Operator:]

And your next question comes from Kim Pacanovsky, Imperial Capital.

[Kim M. Pacanovsky:]

I have a question about your eastern block of -- fairly contiguous block of acreage around the Blades well. Obviously that was a very high rate well. And I don't see that there are any other plans, at least in the wells that you've talked about, to drill in that region. And it looks like there are about 3 permits there. Are those all your permits? And what are you thinking about timing with drilling more on that eastern part of the acreage?

[Walter G. Goodrich:]

Yes, good question, Kim. And yes, those wells are in the Q. We will spud probably 3, perhaps 4 wells. Certainly 3, I think, will get spud between now and the end of the year, down in and around the Blades well, so an area we like quite a lot. Obviously a very nice IP. It performed extremely well through its first, I don't know, 60 to 90 days, somewhere in that range, doing quite well. We like it and we've got a number of permitted locations that we do plan to drill here coming up. I think we actually may have a couple rigs at one time there for a well or 2. And then so I think it's about 3 wells, at least, will get spud between now and the end of the year.

[Kim M. Pacanovsky:]

Okay, great. And then could you just give us an update on the Nunnery well, that was another kind of not a sub-1,000 BOE a day kind of well. Is that also tracking with a flatter decline curve, like the less fractured wells in the southern part of the acreage? I don't know what your fracturing was there, and I know that the lower rate was probably related -- somewhat related to at least the depth in the lower energy in the reservoir. But can you just give us an update on that well?

[Walter G. Goodrich:]

Sure. And you'll see this when we put our updated management presentation out next week. We have recently run tubing in that well, and we've also put it on a jet pump. We've gotten a nice early reaction from the jet pump. Very pleased that we can hold anything like that. We would be very pleased. So we're not, in any way, counting the Nunnery out just yet. Obviously a lower IP, it could have been depth, it could have been thickness. But you'll see that -- be able to see it, and it'll speak for itself next week, probably better than me trying to describe it for you.

[Kim M. Pacanovsky:]

Okay, great. And 1 last quick question. You had mentioned that you were, I think in your last call, that you were drilling through the rubble zone at a steeper angle. Is that now the industry standard? Has that been done in all these most recent wells?

[Walter G. Goodrich:]

Basically yes. Certainly all of our wells, and I think generally the industry is trying to do that as well.

[Operator:]

And your next question is from David Amoss, Iberia Capital Partners.

[David Meagher Amoss:]

It sounds like so far, you've had completion crews that are coming in from other plays, and then leaving after they complete a series of wells. What kind of scale do you and the industry in the play -- what do you think you need in terms of scale to get a dedicated completion crew in the play?

[Walter G. Goodrich:]

Rob, you want to take that?

[Robert C. Turnham:]

Yes, David, we're getting close, obviously. And a great example of that is where we sit right now with the Denkmann, Bates and then likely 2 additional wells coming shortly thereafter, if not back-to-back. Once we start running 4 to 5 rigs, then we'll have scale enough and develop enough wells and inventory to likely have a dedicated frac crew. As we sit here right now, each of the operators has relationships with pressure pumping firms and if we all use the same one routinely, then that would be easy, you'd just -- they'd move equipment in you'd use that one spread to be in a dedicated fashion. But we're getting close. I think as we transition into 4 to 5 rigs, we likely get to that situation.

[David Meagher Amoss:]

Okay, got it. And then you touched on thickness earlier. And just 1 quick last question on the Bates. Do you have -- can you give us a thickness reading or what you're thinking on the Bates thickness versus other wells that you drill?

[Walter G. Goodrich:]

Yes, I don't have the -- this is Gil, David. I don't have the exact thickness in my head, but it's sufficiently thick there, considerably thicker than what we saw over in the Nunnery area. So I don't think thickness should be any issue at all around the Bates.

[Operator:]

And your next question comes from John Raymond (sic) [Freeman], Raymond James.

[John Freeman:]

I just had 1 question. I wanted to make sure that I understood sort of the thought process on the potential asset sales and JV. So you all said you would prefer not to do sort of the non-core asset sales unless you have to given kind of where the gas prices are, would prefer to kind of go with the JV first. So I'm curious if -- is there at some point in the process of a JV when if it takes maybe longer that you expect, then the asset sales kind of come to the forefront? Or kind of how are you thinking about managing that process?

[Walter G. Goodrich:]

Yes, Rob, you want to take that?

[Robert C. Turnham:]

Yes, John, I would say tandem paths. We're not waiting to do anything if -- but I will say, the valuation is very important for a non-core asset sale. We don't have a gun to our head. If we had a number that was sufficiently high, then we would certainly consider doing that when the time is right and we don't need to wait on a JV. The Cotton Valley field is obviously in high demand with recent activity and results being very favorable. So we've already seen quite a bit of interest in an unsolicited manner. And I think we'll continue down that path while we have our discussions on JV. So they're not mutually exclusive. You could see us potentially even do both. But certainly, we're not going to wait on evaluating options.

[John Reardon:]

Okay. And then just last one for me. If I looked at the low-end of your CapEx range, the $325 million, what would that translate into in terms of when the fourth rig was added? To get to...

[Robert C. Turnham:]

That's maintaining the 3-rig schedule.

[John J. Gerdes:]

Okay. So if it's $300 million flat the rest of the year, you'd be at the $325 million.

[Robert C. Turnham:]

That's correct. And I think if we get indication that the capital is coming in, whether it's a non-core sale or a JV, then you could see us contract for the fourth rig at that point. And obviously, the CapEx, the full amount would be if we scale into a 5-rig program by the end of the year.

[Operator:]

And your next question comes from Mike Kelly, Global Hunter Sec.

[Michael Kelly:]

As you transition from delineation drilling back into the fairway of the TMS, I'm curious to what your primary focus is going to be, and if there's anything you really want to test or prove out with your next batch of wells here.

[Walter G. Goodrich:]

Yes, Mike, this is Gil. So really just -- we've always been trying to balance a little bit of what would be more developmental in nature with delineation, and we haven't really -- I wouldn't characterize this as flip-flopping back between delineation and development. But clearly, we now, as I said in our earlier remarks, with the industry activity picking up, we're seeing more and better wells within a certain defined area. And it works out if it make sense for us to kind of focus our rigs in that area for the next few months. So we're going to drill, as I said to an earlier question, we're going to drill some wells down around our Blades well. We like that area quite a bit. We're going to drill some additional wells through southern Amite. And we've got a couple of rigs running in the Crosby area in kind of eastern Wilkinson County. Gaining some traction, posting some more and hopefully better numbers on the scoreboard and getting some oil traction volume is really a part of the focus for the next few months.

[Michael Kelly:]

Okay, great. And there's been a lot of talk on this call on the natural fracturing, and its impact on initial rates. And I was just hoping maybe you could frame this and maybe just quantify the rate of return difference between a well that's ultimately going to have the same EUR, but -- or 2 wells that'll have the same EUR, but one comes on with a pretty prolific rate due to natural fracturing versus one that's not a real hot IP rate, but kind of a flatter decline. What do you think the delta is between the IRRs there?

[Walter G. Goodrich:]

Yes. The easy answer, Mike, is it's very difficult to say. However, as we have said this morning, our Beech Grove crossed over. Though it came in lower, it crossed over within 30 days. And so you're going to see -- if that tracks, say, 600,000 to 700,000 barrel curve out over time, you're going to see a negligible difference in rates of return from that versus a well that would have come in at 1,200 or 1,300 barrels a day. But no 2 wells are exactly alike, so difficult to give you a hard answer.

[Operator:]

And your next question comes from Chad Mabry, MLV & Co.

[Chad L. Mabry:]

Most of mine were answered. Just a couple housekeeping questions if I could. First on the Angelina River Trend. It looks like you drilled a well there, but it doesn't look like that's reflected in Q3 guidance. Just curious when that's expected to come online?

[Walter G. Goodrich:]

Yes, fourth quarter Chad.

[Chad L. Mabry:]

Okay, great. And then maybe for Jan, the $3.4 million of other nonrecurring charges, were those cash charges there?

[Jan L. Schott:]

The first one, the $2.8 million was, but it related to prior periods going back several years. So that's -- but the other one was not.

[Operator:]

And your next question comes from Andrew Gundlach, First Eagle.

[Andrew Stephen Gundlach:]

Let me follow up on the IRR question, which summarized a lot of the discussion over the deeper parts of your acreage. Let me ask that question in a slightly different way. When you are having your JV discussions, financing discussions, do you expect interested parties to value the 13,000-plus feet at the $5,000 an acre? Is there confidence in that today as you look at all the data that you have?

[Walter G. Goodrich:]

Yes, Rob, you want to take Andrew's question?

[Robert C. Turnham:]

Yes. Certainly, it all kind of gravitates back towards this discussion we've been having, which is what are the EUR estimates, what impact do you see by 30-day wedge that's not quite as high. But $5,000 an acre is certainly a very low valuation when you look at what the PV-10 per spacing is on each one of these wells. The number is dramatically higher. So there's going to be an easy math exercise as to show why the $5,000 an acre is a bargain price. But part of the reason we stepped out and delineated was to have that situation where we could show this is what we're seeing in these areas, and therefore, an investor can step up to the table and go ahead and pay that. Now when you get in within the core or the fairway, the numbers clearly have to go up for us to have any interest at all in bringing in a partner. But no reason to think that the deeper acreage where we have our SLC and Beech Grove wells, should not generate the minimum $5,000 an acre in our opinion.

[Andrew Stephen Gundlach:]

Okay, that's obviously very positive. And just help me understand, remind me how to quantify the opportunity. You've said it in terms of 90% of your acreage. I think you said less than 14 or less than 3, I can't remember. But let's just imagine for a moment, that you had 3 more delineation wells, all showing what you just said which is assuming that the Beech Grove cumes come in to meet IRRs equivalent to the shallower depths. At that point, isn't there more acreage than what you -- isn't there a broader acreage opportunity such that there's actually not 10%, but there's quite a bit more? Follow my question?

[Walter G. Goodrich:]

Yes. As to the depths, you are correct, 90% of our acreage is 14,000 feet or more shallow than that. And it obviously runs kind of northwest to southeast. So even though if you're looking regionally as to where those wells have been drilled, there still is a desire and a need to drill further south, but the depths are very similar to where we drill these wells. So we're not going to say every well drilled at the same depth is going to be the same result because we think that you could see some variability relative to naturally occurring fractures. But certainly, with the wells that have been drilled, with the core data that spreads throughout our acreage block, being very consistent with over 1,300 vertical wells that have been drilled, surrounding and including our acreage, which gives you very good subsurface data and well control, the story is there, and we think it's going to be fairly easy to understand. So those are the depths and those are the acreage counts that we have. And no reason to discount acreage that's -- that doesn't have a well on it, but that's within those depths.

[Chad L. Mabry:]

Understood. That's very helpful. Okay, last question. The capital that you partnered, the capital that you seek, do you expect it to be strategic capital, in the sense of companies that can provide expertise in certain areas? Or do you see it really to be more financial capital, similar to what HK did? And do you care?

[Robert C. Turnham:]

Well, Gil, I'll take a shot at that. Obviously we like the cash and carry structure. It's more preferable than -- for us, as to where our balance sheet currently sits, if that's a possibility that would be our preference. We don't need any additional expertise. I don't want to sound arrogant in a response, but we've spent 2 years drilling wells, improving our techniques and basically, tweaking our results, our completion methodology to get the results. So we feel like the technology is there and our expertise is there. It really becomes who is like-minded in their vision. Who sees the potential of this play similarly to us, who's going to be a good minority, non-operated partner with us. Obviously, we have a good one now in Sinopec, and they very well could have an interest in this process as we continue to play it out. But there are plenty others out there and we're going to have those conversations. So that would be our preference.

[Walter G. Goodrich:]

So this is Gil Goodrich, we're running very long. We're going to take a couple more questions and then wrap it up.

[Operator:]

So your next question comes from Jeffrey Campbell, Tuohy Brothers Investment Research.

[Jeffrey Campbell:]

I'm going to ask 2 questions. It's going to sound like I'm on the Encana call, but I'm using them as a reference point. My first question is Encana recently said that extended laterals were their last mile in declaring the play commercial, the TMS commercial for them. What do you see as the main impediments, currently, to increasing lateral length?

[Walter G. Goodrich:]

Yes, Jeffrey, this is Gil. Nothing, other than just time and money. So wells in the laterals have generally, not exclusively but generally, gone quite well and we could keep scooping out there and get more lateral length. We would at least internally at Goodrich, take a slightly different approach. And that is that we've seen some laterals including our Blades well that were only 5,000 feet that we think are going to be extremely economic wells. So while we generally believe that longer is generally better and we, as we've said are targeting 6,000 to 6,500 feet, and we're happy to see others targeting longer laterals, the problem today is just trying to balance what near-term well costs are versus anticipated results. And so, if it ultimately looks like 8,000 or 9,000 feet is the right way to go from an economic standpoint, then that's what we'll be doing. In the near term, we think that anything north of 5,000 and certainly 6,000 to 6,500 feet is certainly good today.

[Jeffrey Campbell:]

Okay. And kind of quickly going back to the porosity and matrix stuff, but in a little bit different way. First of all, am I correct that the SLC was the first modern well that was drilled in West Louisiana Parish in that area? And how did it perform relative to your predrill expectations? In other words, were you kind of -- you already had a theory about matrix and porosity going into that well or is that not the right way to think of it?

[Walter G. Goodrich:]

Yes. So this is Gil also. Absolutely, we had a theory about thickness and matrix porosity and permeability, that's why we drilled there. The first part of your question, I believe is correct, and I'm going to try to confirm it. West Feliciana, the Devon-Murphy well was drilled in -- a little bit west of that in West Feliciana, and that was a horizontal. So again...

[Jeffrey Campbell:]

Right. But it didn't have your kind of completion methods?

[Walter G. Goodrich:]

That's correct, it did not. Much smaller frac job, and that data is outlined for you in our management presentation, so you can look at that comparison. But other than that, ours would be the first modern era horizontal after the Devon Murphy well.

[Jeffrey Campbell:]

So just to reiterate the last part of my question. Did the SLC come in consistent with what you were thinking was at least potentially possible when you drilled the well?

[Walter G. Goodrich:]

Absolutely. I guess, would we have rather seen some additional what we think is natural occurring fractures and seen a 1,200 to 1,500 barrel a day IP? Sure. But we're very, very pleased with 900 barrels a day, and think it's going to be a very good well.

[Jeffrey Campbell:]

Okay. And my last question to finally get away from the TMS. Encana discussed Haynesville Shale recompletions in their last call, that cost $1 million, produced 4 million per day IPs. They say it had a 3-month payout. It was the best returning project in their portfolio, including oil, and I've also heard that EXCO is doing some similar recompletions. Is this something that you're looking at or do you have wells that would be good candidates for this sort of work?

[Walter G. Goodrich:]

Yes. So you're referring to just a re-frac?

[Jeffrey Campbell:]

Yes, the re-fracs for $1 million, yes.

[Walter G. Goodrich:]

We're looking at that, and obviously you can't go and do stages. All you can do is just go re-frac whatever you've already opened up. We're watching that very carefully, and certainly, something that we would consider doing in the future. And in terms of candidates, yes we've got, I don't know the exact number, 80-some odd Haynesville wells that we have an interest in. All of which, theoretically would be candidates.

[Operator:]

And your next question comes from David Snow, Energy Equities.

[David Snow:]

Yes, you had 2 wells, I believe both probably were in Encana the nonoperated ones had, had a very good flow rates. So I'm wondering if you can give us any color on those in terms of proximity or depth or whatever you can tell us.

[Walter G. Goodrich:]

Sure, Dave, that's very easy. If you'll pull up our management presentation and go to the activity map, you will see both the Lewis well and the Mathis well, identified with a box and an arrow, both are in Amit County, kind of central to southern Amit County, certainly within that core fairway area we've been talking about this morning.

[David Snow:]

Are they offsetting -- I'm trying to look on at that map, are they offsetting any really strong wells that you've drilled?

[Walter G. Goodrich:]

Yes, their Lewis well would be west of our Goodrich CH Lewis well, which is, if not our very best, certainly close to one of our very best wells. The Denkmann well we are currently completing would be slightly west of their Mathis well, and just southeast, south southeast of their Lewis well. Our CMR well is just a little bit east of the Lewis and just north of their Mathis well. So quite a few wells in that area and quite a few additional wells coming up in the near-term drilling plans. Both us and them.

[David Snow:]

Is there anything different in their completions than what you've been doing?

[Walter G. Goodrich:]

No, I would say both of those are pretty similar, finally getting to around to being pretty similar to what we've been doing, David.

[Walter G. Goodrich:]

Thank you, everyone.

[Operator:]

I'd now like to turn the call back over to the Bill Goodrich, Vice Chairman and Chief Executive Officer, for closing remarks.

[Walter G. Goodrich:]

Thank you, Sue. Sorry we ran long. Perhaps it was the length of our answers to your questions. But we appreciate your attendance and we look forward to giving you our third quarter results in early November. Thank you.

[Operator:]

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