GMX Resources' CEO Discusses Q2 2012 Results - Earnings Call Transcript

Aug.12.12 | About: GMX Resources (GMXRQ)

GMX Resources Inc. (GMXR) Q2 2012 Earnings Call August 9, 2012 9:00 AM ET

Executives

Alan Van Horn – Manager, IR

Michael Rohleder – President

Tim Benton – EVP, Geosciences

Ken Kenworthy – CEO

Analysts

Welles Fitzpatrick – Johnson Rice

Curt Starer – Aberdeen Asset Management

Richard Tullis – Capital One

Noel Parks – Ladenburg

David Epstein – CRT Capital

Operator

Good day, ladies and gentlemen, and welcome to the Second Quarter 2012 GMX Resources Incorporated Earnings Conference Call. My name is Huey and I’ll be your operator for today. At this time, all participants are in a listen-only mode. Later, we’ll conduct a question-and-answer session and instructions will follow at that time. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the conference over to our host for today, Alan Van Horn, Manager of Investor Relations of GMX Resources. Please proceed.

Alan Van Horn

Thanks, Huey, and good morning and welcome to the GMX Resources Incorporated second quarter 2012 earnings conference call. We appreciate, as always, the participation of our shareholders as well as brokers, analysts and friends. Today, we plan on to review the accomplishments we’ve achieved in the second quarter and in the first half of 2012.

On the call this morning for GMXR is Ken Kenworthy Jr., our Chief Executive Officer; Michael Rohleder, our President; Jim Merrill, our Chief Financial Officer; Tim Benton, Executive Vice President of Geosciences; Harry Stahel, Executive Vice President of Finance; and Darrel Hardy, our Controller.

During this call, we’ll review our results for the second quarter of 2012 and provide our listeners with an update on our operations that we’re actively involved in. This conference call is being recorded and will be available for replay approximately one hour after its completion. Both the conference call with an accompanying slide presentation and our second quarter earnings release can be found on our website at www.gmxresources.com.

Before we begin, I want to remind everyone that our conference call will contain forward-looking statements, including our expectation of future results. The actual results might differ materially from those projected in these forward-looking statements. Additional information concerning factors that could cause the results to differ materially from those forward-looking statements are contained in our press release dated August 8, 2012, announcing our earnings, as well as disclosures in our public reports on Forms 10-K, 10-Q and 8-K filed with the SEC and available on the SEC website.

During the conference call, we’ll also make references to adjusted net income, discretionary cash flow, which are non-GAAP financial measures. Reconciliations of these non-GAAP measures to the applicable GAAP measures can be found in our earnings release. Now I’d like to introduce our President, Mr. Michael Rohleder, for some opening remarks.

Michael Rohleder

Thanks, Alan, and thanks all of you for being on the call this morning. Oil continues to be the driving economic force of the energy sector. Natural gas reserves and natural gas storage are at all-time highs, and natural gas prices were at 10-year lows during Q2 of 2012. Our transition to oil is made even more urgent by these factors. The company must direct its capital to the most economic projects, which coincidentally are those that deliver the highest shareholder value.

This is why we’ve been focused on the transition from being mostly a natural gas producer to being a more balanced producer of oil and natural gas. In order to make that transition a reality, we embarked on a number of different interdependent plans, finding and acquiring acreage, finding investors willing to support the plan, building an operational footprint in an area where none existed, reallocation of our CapEx from natural gas to oil only and accelerating all of this in a challenging market environment.

The successful transition to oil is a vital building block of GMX Resources’ shareholder value. Dealing with the facts today, the solution to our challenges is to continue to focus on the steps necessary to achieve the goal. Our oil production has grown 107%. We’re on budget with our 2012 CapEx forecast. We’re on budget with our 2012 G&A reduction goal and expect to reduce G&A by another 20% in the year 2013, and we’re on budget for our 2012 LOE forecast. So we’re moving the company in the direction that we set course for 18 months ago.

It’s not even been a year since our first Bakken well came online and we have produced more oil in the first six months of 2012 than we did in the entire year of 2011. More specifically, looking forward to 2013, as the company’s liquidity position improves through drilling results, cost reductions and asset optimizations, we’ll be able to accelerate our business plan.

I’ll now turn to the presentation that, as Alan has said, is posted on the website and begin on page three, which describes the major advancement in near-term liquidity. One of the near-term challenges the company faces is the maturity of the company’s convertible notes due in February 2013. The remaining balance of $52 million is the focus of an exchange offer we launched this morning just prior to this call. Assuming we are successful in this offer, we would address the current liquidity issues for the 2013 notes along with a limited portion of our 2015 (inaudible) through the issuance of up to $60 million of new notes maturing in 2018.

If the exchange offer is fully subscribed by holders of our 2013 convertible notes, we would also issue approximately 15 million shares of common stock to those noteholders, representing slightly less than 20% of our outstanding shares of common stock. I know all of you will have lots of questions regarding this and I’m going to have to refer you to the tender offer documents that we filed with the SEC for any questions regarding the terms of this offer.

On slide four of this deck, listed are the specifics related to another liquidity-enhancing project that’s going on simultaneously with the tender offer. We are well into the process of offering our Cotton Valley assets for sale. We certainly expect this to be successful, particularly given the current market dynamics and comparable deal flow. An especially attractive part of this offer is the upside represented by the available undeveloped Cotton Valley acreage included in it. The outstanding results of other nearby operators who have drilled long lateral Cotton Valley horizontal wells has really put our acreage in the spotlight.

On slide five, we doubled our oil production from Q1 to Q2. Our wells, both the operated and non-operated, in McKenzie County’s peak rates have averaged 1,660 BOE per day. Our last three wells spud to TD times averaged 31 days as compared to the first four wells we drilled in the Bakken that averaged 45 days. Our forecasts are always subject to the unknown and the unknowable and as an example, our Q2 production was attenuated by a number of independent and unrelated mechanical, logistical and operational challenges, affecting the performance of both operated and non-operated wells. In aggregate, our wells were only producing 72% of the time during the quarter.

All that and the potential of a Cotton Valley sale will have an effect on our Q3 production estimates. We have not yet given specific guidance for Q3 production. However, it’s unlikely that we will exceed Q2 oil production, particularly if we are successful in selling the Cotton Valley. Our plan is to update you with more information later on this quarter.

On slide six, we continue to focus on the things we need to do to succeed in the transformation of the company. Our acreage in North Dakota has been derisked through our drilling and that of other major operators near us. Drilling in this derisked area has resulted in 107% growth in oil production as compared to last year, and in fact, as I mentioned earlier, we produced more oil in the first six months of 2012 than the entirety of 2011. Our quarter-ending exit rates are significantly higher and our expectation of reducing the drilling time and costs even further has been facilitated by the deployment of the H&P FlexRig.

The Niobrara still represents a significant asset upside to the company. As we receive additional Niobrara seismic analysis, we are continuing to evaluate areas and formations within our acreage base that will be targets for future development. This analysis and the clarity it provides gives us an opportunity for successful future development of this more than 40,000 acre position either through a JV or even a partial sale, which of course would increase the company’s liquidity position, facilitating more oil development sooner. Tim Benton will add his comments related to the Niobrara in a few minutes.

Slide seven is an accounting of our operated and non-operated wells since we began work in the Bakken in late 2011. The peak IPs of our operated wells in McKenzie County have averaged about 18% greater than those of our non-operated wells. The Basaraba well, which is a middle Bakken target in Billings County, is currently drilling the laterals and is expected to be online and producing in the last half of September.

The Fairfield State well is currently waiting on completion. Two of the first four stages of the sliding sleeve pressured out, resulting in a suspension of that completion process. We’ve determined that the best way to finish the stimulation of this well will be to use a plug and perf scheme. Even with the partial and less-than-perfect results in the first four stages, the well has produced enough oil to substantiate the decision to push forward and finish this completion.

And on page eight, lastly for my part of this formal presentation is a pro forma of the company’s potential reserves after the proposed sale of the Cotton Valley. The company has, over time, accumulated abundance of great assets. This chart really exemplifies the opportunity for growth that we have, even considering a possible sale of the Cotton Valley. Our focus today is on the 150 million barrels of oil available to us in the Bakken and the Niobrara, but we still have over 1 trillion cubic feet of gas available to us in East Texas, primarily in the Haynesville. This is truly an upside opportunity and will represent significant value when natural gas prices allow us to earn a meaningful return on our investment.

Our East Texas gas field is a unique, high quality asset that is held by production and has infrastructure in place and allowing us to resume drilling almost immediately. By applying long lateral drilling techniques first experienced initially in the Haynesville and continuing in North Dakota, we believe we can drill and complete even longer laterals in East Texas, significantly increasing the well economics, while greatly reducing the total capital requirements for full scale development. The total potential reserves, oil and natural gas, are considerable and represent significant upside for the company and its shareholders.

Now, I’ll turn it over to Tim for more specific operational update.

Tim Benton

Thanks, Mike. Directing your attention to slide 10 is our asset overview, showing the four positions of GMX Resources. On this, you can see a recap of acreage footprint, modeled locations and operational elements for the Williston, DJ and East Texas basins. Obviously, two are crude oil opportunities, one liquids rich and one, dry natural gas.

Going to the Bakken, we continue to assess the significant impact of modern completion schemes from swell packers and completion stages on well results over the last few years. Slide 11 is an update of a past presentation showing the 30-day IP distribution profile Bakken completions split into three areas in North Dakota. First, the top curve in blue is from the Parshall Field, which as the industry knows, is unusually successful and located within the East Nesson sub-basin. We then depict data from the remainder of that area as simply East Nesson. Lastly, we plotted results from the West Nesson sub-basin.

We further broke down these last two subsets as pre- and post-2009 in a rough attempt to remove the impact of changes in completion schemes. The wide range of IP results, regardless of the area, supports branding this as a resource play. The smaller sample size of pre-2009 well results in the West Nesson sub-basin underperformed the East Nesson numbers.

Post-2009 West Nesson results, however, are on par with East Nesson. We believe this thinking validates the large scale derisking assessments and multiple acquisition transactions in the $1 billion zip code in this very prolific area.

As follow-on to this observation, we show the paleotopography the Bakken deposition in the upper right-hand corner of this slide. Interestingly, we see an area ripe for organics proximate to Parshall. Subsequent movement along tectonic shear zones influence the depositional pattern of the upper Three Forks through the middle Bakken section and reflects similarity between the Rough Rider and Southeast McKenzie areas of development.

Slide 12 sets the stage for comparing well results when we have evolving completion schemes sorted by the completion dates that we saw on slide 11. You can see here work by Brigham through a published paper in which they frame the idea that more stages equal better results and reflected in the stacked oil performances in the lower-left-hand corner of the slide.

In that work, they suggested computer modeling confirms aggregate improvements in well performance as the number of stages increase. We were able to get a good match on their work using a 0.025 mold RC rock in the various fracture assumptions shown on the slide. They make the additional claim that using a plug and perf scheme instead of sliding sleeves and there’s the better completion results then you might note that we talked about using a plug and perf on the remainder of the Fairfield well and our completion.

There is agreement that more fractures with shorter lateral half-length size – shorter half-length theoretically give better well results in tighter reservoirs. The lower-right-hand corner image shows the results from a microseismic consortium that seems to indicate that a longer fracture half-length from a sliding sleeve completion. However, the core essence of Brigham’s claim is that a defect from a shaped perforation charge is more likely to cause multiple fractures, taking profit as opposed to sleeve port opening. In other words, it appears that during a sliding sleeve completion, there are fewer and lower amplitude shear events and that the microseismic mapping is scalable to fractured network or stimulated reservoir volumes, which is the main driver for well productivity.

Moving to the DJ Basin, we have our oil-rich 40,000 net acres of targets in the Niobrara, Codell, Greenhorn and J Sands, as well as a new focus on deeper Pennsylvanian/Permian intervals. On slide 13, we show a seismic line of intense fracturing extracted from the Chugwater 3D seismic shoot and as compared to a similarly scaled piece from a (inaudible) just southeast of the Silo. We are very encouraged by this data. To refresh your memory, this area is located just north of the Silo field where horizontal wells drilled in the late 1980s, early 1990s have produced up to 487,000 barrels of oil, averaging 225,000 barrels. Further from this data, we are netting faults with minor verticals of seismic.

Slide 14 sets up our sale process, the rationalization for value as we’re modeling 77 net locations of 7,500 foot laterals in the Cotton Valley. The 7.5 Bcfe EUR includes 18% NGLs and condensate. We reported previously that the Samson Kain well, a 7,000 foot lateral on the southeastern edge of our 100% operated area, had an IP of slightly less than 8 million a day. We now have four months of history from the Railroad Commission on this well that shows a well performance exceeding the model that we put out last fall.

This play was, to some extent, overshadowed by the Haynesville in spite of a jump-start in 2006 with Devon’s announcement of the Carthage Haygood Lois completion at 8 million a day. Since that time, over 250 Cotton Valley horizontal wells with an average lateral length of 3,300 feet have been drilled in the East Texas Basin, not including Everton. The play was also hindered by relatively short laterals due to technical and regulatory considerations.

GMX drilled three short laterals in 2006 followed by Devon in 2007 in our area of operations. The latest production updates on (inaudible) confirm about 1 million cubic foot of EUR per foot of lateral. We’ve built a computer model for the short lateral case with first generation completions near GMX’s acreage and scaled that up to the long lateral seen on this slide and we’ve validated that resource with core data. Bottom line, we’re encouraged by the results of the first long lateral in this area and we believe this will be a driver of upside valuations.

Turning now to slide 15, we return to the proven success of our core operating position of Haynesville in East Texas, where we have derisked natural gas resource base of 25,000 net acres. As a perspective, this play went from zero to 8 Bcf a day in less than four years, producing around 12% of the United States’ natural gas supply in late 2011.

As a reminder, GMX drilled or caused to drill 19 vertical penetrations in 2006 before the Chesapeake announcement that set a large value on acreage positions in this remarkable play. We have considerable research and development in this area that allows us to message in excess of the Tcf of natural gas resources. The combination of major improvements in horizontal drilling efficiencies, longer laterals, reduced perforation spacings resulted in greater well economics vaulted this play into a game changer for North American natural gas.

We will continue to assess, as Mike said, the resumption of drilling operations relative to natural gas prices as we look to this position.

And with that, I will turn the presentation over to Ken.

Ken Kenworthy

Thank you, Tim. As you have just heard, we’ve been working on converting to an oil producer, improving the value of our oil asset, replenishing liquidity to fund our oil drilling and interest expense, moving short-term debt out to 2018, reducing debt and G&A. Our business plan calls for converting our Bakken locations into oil producers. Real asset growth, revenue growth and EBITDA growth come when multiple rigs are drilling our oil development.

Our plan calls for two more rigs to be added when liquidity permits. Each rig adds approximately $18 million to annual revenue the first year, $36 million the second year and $48 million, the third year, providing $14 million, $29 million and $38 million annually to EBITDA from each rig addition.

After our Cotton Valley sale and adding a second and third rig, this business plan can grow our revenue the next two years by 25% and 60% year-over-year. EBITDA can grow 60% and 100% year-over-year, leading to GAAP net income, again, in early 2015. Our revenues should be 46% from oil and NGLs in 2012, 81% in 2013, and 88% in 2014.

We will still have over 1 Tcf to drill in our Haynesville/Bossier development when natural gas prices allow us to earn a meaningful return on our drilling capital. We have reduced debt this year and expect to finish the year with $40 million less debt.

Each year, we will look at strategies to increase our asset value and opportunities to lower our interest expense and reduce outstanding debt. We have taken major steps over the last four years to survive this tremendous bear market for natural gas producers. We will achieve a revenue transformation from 96% natural gas to 88% primarily oil in 2014. Our future growth will be from developing our world-class natural gas or oil fields.

Thank you. This ends the formal presentation. I would now like to open the phone lines for questions.

Question-and-Answer Session

Operator

Thank you, gentlemen. (Operator Instructions) Our first questioner in queue is Welles Fitzpatrick with Johnson Rice. Please go ahead. Your line is now open.

Welles Fitzpatrick – Johnson Rice

Good morning.

Ken Kenworthy

Good morning, Welles. How are you?

Welles Fitzpatrick – Johnson Rice

Good. Good.

Operator

I think we may have lost him. It looks like our next questioner in queue is Curt Starer with Aberdeen Asset Management. Please go ahead. Your line is open.

Curt Starer – Aberdeen Asset Management

Good morning, gentlemen. Just a quick question, trying to drill down a bit on the Cotton Valley sale. You mentioned third quarter production would be off if the sale is affected. Can you talk to the production that is attributed to the Cotton Valley at this point? Hello?

Ken Kenworthy

Yeah. We’re here.

Curt Starer – Aberdeen Asset Management

Right. Okay.

Tim Benton

No, we’re not really positioned to speak to those values today, sorry.

Curt Starer – Aberdeen Asset Management

With the asset sale, would any hedges move with the assets?

Ken Kenworthy

No. Our current hedging position we could sell off the Cotton Valley without having to liquidate any oil and gas hedges.

Curt Starer – Aberdeen Asset Management

Well, I didn’t know if you’d sell the hedges along with the reserves and production.

Ken Kenworthy

Right now, our gas hedges, where they’re at, they’re a liability position due to the movement in gas prices. And so that wouldn’t be part of the sale.

Curt Starer – Aberdeen Asset Management

Okay. What about Haynesville? Has there been – with well costs coming down, lower fracking costs and so forth, any change in economics there when the Haynesville would be productive for you guys to start putting capital back to work there?

Michael Rohleder

Yeah. This is Mike. We don’t see that as a near-term event. Obviously, we watch the same things you watch. We see that well costs are coming down, rigs are laying down, operators are curtailing gas production. So all of those are great signs for a recovery sooner than I think people expect. I think for us our capital shift has to go to wherever we get the highest economics for us right now; that’s drilling oil in the Bakken. And as I said in my opening remarks, because of the setup in East Texas with acreage and infrastructure, we can be ready to go back into East Texas at whatever point that economically makes sense, but I don’t see that on the near-term horizon right now. Go ahead, Tim.

Tim Benton

Yeah. All right. I would just add that, if you take a look at the, I mean on the first year production on the Haynesville and on the areas that we’re operating here in 1.5 Bcf in that first year of production zip code and I think the industry has learned its lesson that the perspective of what the gas price is going to be in that first year is going to be a real strong driver for making a decision to allocate capital in a tight shale play.

Curt Starer – Aberdeen Asset Management

Okay. Switching to the Bakken, just curious with the well costs. Are you seeing any improvement there?

Ken Kenworthy

Yes. As we mentioned, we’re seeing well costs about $8.5 million and this is pre-implementation of the H&P rig that’s currently drilling on the Basaraba as part of moving H&P. We no longer have to pay for a main camp, no longer pay for the drill pipe out there, so that all ties that to be about a $0.5 million of savings and we think with the experienced crew of H&P and better well performance and tee times, that we’ll see continuing decrease in well cost.

Curt Starer – Aberdeen Asset Management

Okay. All right. That’s everything. Thank you, gentlemen.

Michael Rohleder

Thank you for the questions. Appreciate it.

Alan Van Horn

Operator, can we have the next question?

Operator

Yes sir. Next questioner in queue is Welles Fitzpatrick. Please go ahead. Your line is open.

Welles Fitzpatrick – Johnson Rice

Hey, guys. Sorry about that. Don’t know what happened there.

Michael Rohleder

Welcome back, Welles.

Welles Fitzpatrick – Johnson Rice

Good to be back. I was just asking if there’s anything – any timetable on the Niobrara transaction with that 3D back.

Michael Rohleder

No. Again, I don’t want to be misleading. I think what’s happened in the last several months is as we started to get deliveries of this 3D seismic and Tim’s guys have been able to begin to analyze it and even to the point of selecting some potential targets, it’s given us a new appreciation for the upside potential of the play.

We don’t have any process in place. There’s no – there’s nothing going on in terms of a process like we have going with the Cotton Valley in terms of sales. I wouldn’t put that on the radar screen as a near-term event, but I think what happens is, is we get more and more of this information into the hands of our engineering team. We get more comfortable with the fact that this potentially could be a very big upside for us. And therefore, if somebody’s interested in a JV in the Niobrara or potentially buying a piece of it, we’ve got a better set of data to look at.

And, Tim, you might want to...

Tim Benton

No, I would just add and, of course, as we spoke in the prepared remarks, we are looking at the Pennsylvanian and Permian targets in this area and so you’re looking at – as you look at those deeper structures, there’s a bit more work to do on the seismic in terms of thinking about how you optimize your initial test somehow allowing you to establish the viability in the deep step as well as the shallower Niobrara, Codell, and others, if you will.

Also, if you’ve been paying attention to the play, you’re seeing some movement by some other operators in the play, looking at these deeper ideas, if you will, and it’s not necessarily a brand new idea, certainly the – you’d have the production from those intervals further up, shallower on the east side of the basin, if you will, but those represent conventional targets and now, again, maybe the question is, has this become another tug-of-war, sure, the Granite Wash type opportunity for somebody and we’re working on getting that sorted together.

Welles Fitzpatrick – Johnson Rice

All right. When the Wyoming State and BLM lease sales post, I think it’s today and Monday, is there any acreage number that might tempt you back into that market?

Tim Benton

I don’t think we’ve got a budget for really adding to our position in the area right now.

Michael Rohleder

We have a multi-year acreage position already. We’ve got plenty of drill – development opportunity up there, Welles, and our leases originally were written at five years; most of them have five year additions. So we’ve got gross number over 600 or right at 600 locations up there.

Welles Fitzpatrick – Johnson Rice

I’m sorry. I meant if you saw offsetting acreage going for $2,000, $3,000, $4,000, I mean would that tempt you to other way, tempt you back into looking at a JV or a potential sale or are you guys pretty sure you want to keep it in house?

Michael Rohleder

No, I get you. I misunderstood your question. No, we’re not. I don’t want you to think we wouldn’t be amenable to the idea of a JV or a partial sale. I mean, we still think in terms of having an abundance of assets up there that could be terrific to find a JV or a partial sale partner in that. I think again, Tim’s point is right: we’re just now seeing enough offset operator results. We have some terrific seismic examples to talk about. Our engineering team is looking at different formations and different targets within our basins. So I think we’ve got some terrific things to show someone, but as I said before, we’re not in an official sales process. But that doesn’t mean we wouldn’t be interested in that.

Welles Fitzpatrick – Johnson Rice

All right. Perfect. Thanks. Thanks, guys. That’s all I have.

Operator

Thank you, sir. Our next questioner in queue is Richard Tullis with Capital One. Please go ahead. Your line is open.

Richard Tullis – Capital One

Thanks. Good morning.

Michael Rohleder

Good morning, Richard.

Richard Tullis – Capital One

Mike, I know you guys just mentioned the costs for the Bakken. How does that split out between operated and non-operated wells?

Ken Kenworthy

You mean the total CapEx?

Richard Tullis – Capital One

Yeah. Well, are you seeing difference in AFEs from your non-op partners for wells?

Ken Kenworthy

Yes. Yeah. We’ve seen probably – probably say from $9 million to maybe even upwards to $12 million depending on – it seems like the larger operators have the higher AFEs. So, yeah, we are seeing – they are higher than ours. Price proportionate, but we haven’t had a large non-op working interest. I think, for the year, we’ll probably have one net non-op well. So their larger AFEs are not significantly impacting our CapEx budget.

Richard Tullis – Capital One

Okay. And as you move forward into next year, do you see a lower level of – even lower level of, say, non-op activity and just mainly focus on your own acreage or where you operate, at least?

Tim Benton

I’m not sure, really, how you can predict that, to be frank. As you look at our acreage position, as we put it in bins of working interest and as we proceed putting these operated units together, certainly, we’re doing trades and trying to increase, certainly, our working interest on our operated units. In the – as you take a look at the basin in general, certainly you’ve seen some of the operators dial back a little bit on their activity. Oxy has done that. I think new fields really kind of in a let’s go figure out what the spacing is going to look like in the Bakken before they start ramping up their activity again.

Richard Tullis – Capital One

Can you say what the cash flow generation is currently from the Cotton Valley/Pettit asset?

Michael Rohleder

All of that information is, unfortunately, in the deal flow process right now. So we don’t want to publish that data at this point.

Richard Tullis – Capital One

That’s fine, Mike. I know you mentioned the Samson well near your Cotton Valley acreage at horizontal. I may have missed this during the opening remarks. How many other recent wells near your acreage have been drilled horizontally into the Cotton Valley?

Tim Benton

Richard, I’m going to have to pull this from memory. It depends on how far out you want to go away from our acreage. In the greater Panola, Harrison, Rusk County area in excess of 250. I’d say, if you just limit that to wells within a 20 or so mile area east and west in the syncline trend, you’re probably 30-plus – maybe 40 wells within that area.

The Samson well, though, represents, really, the first long lateral that’s been drilled that we have any data on. Actually, they drilled another long lateral just to the east of that, just south of our 30% area and not too far from our multi-lease. And we’re just a coffee talk or coffee shop rumors on that well, but we don’t – we’re encouraged by what we hear, but bottom line, those will be the only two longer laterals in that area. Devon’s also doing some laterals or Cotton Valley horizontal wells, back to the east of our Verhalen unit and those wells, we don’t believe have made it into the public domain yet.

Richard Tullis – Capital One

Okay. That’s all from me. Thank you.

Michael Rohleder

Thank you, Richard.

Operator

Thank you, sir. Our next questioner in queue is Noel Parks with Ladenburg. Please go ahead. Your line is open.

Noel Parks – Ladenburg

Good morning.

Michael Rohleder

Good morning, Noel.

Noel Parks – Ladenburg

Just a couple things. I did notice and I wasn’t sure if you talked about this earlier, but the pre-announced total production number you gave seemed to be a little higher than the actual and the difference seemed to be on the gas side. Was that related to some of the sort of just general infrastructure, et cetera, challenges you were talking about or did that relate just to the Bakken?

Ken Kenworthy

I’m not quite sure. I didn’t catch all your questions, the first part on the production being more to do with gas?

Noel Parks – Ladenburg

Yeah, did the gas production come in a little lighter than you expected sort of in that mid-June timeframe what you are looking for?

Ken Kenworthy

That’s correct. We had a little bit lower than expectation there.

Noel Parks – Ladenburg

Okay. Any particular driver behind that?

Ken Kenworthy

There was some, I’d say, infrastructure constraints, but that’s probably the biggest driver of that.

Noel Parks – Ladenburg

Okay. And it was –

Ken Kenworthy

And also you could say with the natural gas price environment, we’re not actively working over wells as in a higher price environment, so that contributes a little bit to it as well.

Noel Parks – Ladenburg

Sure. And, sorry.

Tim Benton

I’m sorry. I’d just add just, you’re going to see in general with natural gas prices collapsing, operators are going to suspend or pare back their treatments that they do, their normal maintenance and treatments that they do on those wells. And so to some extent that exacerbates the natural decline that you see in production.

Noel Parks – Ladenburg

Got it. And actually, again, I got on a little bit late so I don’t know if you talked about this. Is the gas takeaway situation in the Bakken having much of an impact on you as far as being able to bring wells online? I don’t know how the (inaudible) has been about flaring lately and so forth.

Michael Rohleder

The short answer, Noel, is no. Our agreement with (inaudible), which covers the majority of our wells in McKenzie and Billings area because it’s in immediate proximity to their gas gathering system. We actually have a gas purchase agreement, so they’re buying the gas, they are processing the gas and they are paying us both dollars for residue molecules as well as dollars for NGL barrels.

So right now, the only wells that we don’t have an immediate plan for connecting the gas are the two wells in Stark County. So other than the fact that there’s sometimes a bit of a timing delay, not extensive, but a little bit of a timing delay for (inaudible) to actually connect the wells, so we may start selling gas 30 days or so after we start selling oil, but there’s not an immediate infrastructure issue for gas takeaway.

Noel Parks – Ladenburg

Great. And thinking about just the overall deal environment for assets now with so much stuff in the market, we saw oil and gas sort of change positions with gas strengthening for oil. While oil was going back and now oil seeming to stabilize and gas has had a little bit of a rough week or two. When you’re talking with folks out there, do you have a sense that people are all over the map about sort of the bid-ask for a price deck to use for – so looking at asset valuations, do you think there is kind of a firming consensus of what to pay? We have seen a couple decent size deals, for example, on the Eagle Ford close in the last few weeks.

Tim Benton

Well, that’s a great question. I would say that the M&A market right now is being driven to some degree recently by a resurgence of interest in natural gas assets. I think the general consensus is that natural gas has hit a bottom and yeah, so the buyers are going to have, I think, a more aggressive view of what sort of price deck that they’re prepared to put on an acquisition.

The oil play certainly, I think you saw – EOG got rid of their non-op position in the Bakken. That number hasn’t been publicly released, but if they sold $1.2 billion worth of assets in the, I believe, first half of the second quarter of this year, you’ve got to think that the Bakken was a pretty good chunk of that. Long story short, we think it’s a healthy market in terms of buyers that are out there and everyone keeps their price decks pretty confidential. So I’m sorry that we’re not positioned to share that with you.

Noel Parks – Ladenburg

No, what you what you were able to talk about was definitely helpful. And just the last thing, if I understood you right, you were saying that in the event, for instance, we have a more normal winter and we hopefully say goodbye to these sorts of prices in the $2s and so forth, on some strength in gas prices, I think you expressed some confidence about being able to ramp up again in the Haynesville pretty quickly.

And I guess I was just wondering if you really have a sense or you still have enough equipment up there to make that possible I guess was on the, I guess typically on completion side. And also, since everything has sort of gone through a chill in the Haynesville, in your part of the play, has the infrastructure matured enough that you wouldn’t suddenly face any new problem with this if we saw like a decent sized ramp-up there?

Tim Benton

Well, and if you’re going to describe an infrastructure as high-pressure pumping capability, certainly the service companies have made that capability out of that region to the Eagle Ford to the Permian, if you will, but our view of that market in general is that those of – a pretty big buildup in horsepower capability. Over the last few years and that, certainly that got interrupted and I’d say in general that that market is oversupplied.

But any play you’re certainly, as you see, any time you change the demand for the products, certainly you’re going to see prices firm, if not go up, but that’s something, I promise you, the service companies are grinding on that issue. But really, I think it boils down to, I think the producers have to see I think $4 or $5 gas and believe that that $4 or $5 gas is going to hang around for a while before you see a massive inflow of capital and the demand for the infrastructure to handle that.

Noel Parks – Ladenburg

And I guess with the example of $4 to $5 gas, I mean, I guess, in particular the strip is what you’d really want to see, right?

Michael Rohleder

Fair enough.

Noel Parks – Ladenburg

Okay. Okay, great. That’s it from me. Thanks.

Ken Kenworthy

Thanks, Noel.

Operator

Thank you, Noel. Our next questioner in queue is David Epstein with CRT Capital. Please go ahead. Your questions, please.

David Epstein – CRT Capital

Good morning. In the releases, it says the new notes are not secured by the subsidiaries, the notes for the exchange. I just wanted to confirm the new notes also would not have guarantees from this, separate from any security. Correct?

Ken Kenworthy

That’s correct.

David Epstein – CRT Capital

Okay. Also, what assets and what operations, if any, sit at the parent?

Ken Kenworthy

Run that by me again? What operations are at the parent?

David Epstein – CRT Capital

I am bringing it up because it’s highlighted in the press release that it’s not guaranteed by the subsidiaries or secured by the subsidiaries. So I just want to know what actually is at the parent entity. I assume your cash sits at the parent, but like are receivables at the parent? Do you conduct any operations out of the parent?

Ken Kenworthy

Yeah. I’d phrase it all significant assets are held at the parent, especially liquid assets.

David Epstein – CRT Capital

Oh, liquid assets. But what about all significant drilling assets?

Ken Kenworthy

Yeah. I’d say all, significantly all assets are held at the parent GMX level. The only significant subsidiary that would have assets would be Endeavor Gathering, which is the pipeline that’s in the system that’s 60% owned by us. But other than that, all significant assets are at GMX.

David Epstein – CRT Capital

Okay, and that’s interesting. So you have no meaningful E&P subsidiaries?

Ken Kenworthy

That’s correct. I’d point you to the – in our 10-Q, there’s a footnote that breaks out all the assets and income statements between the parent and the subsidiaries. That would give you some guidance there.

David Epstein – CRT Capital

Okay, great. And I think you said, liquidity permitting, that you would add a second rig potentially in Q3 and Q4. And assuming, even if you do get the 2013 to fully subscribe to the exchange, I assume the other source of liquidity is coming from the Cotton Valley sale. How far do you think your liquidity gets you? Because it seems like right now, you still would be running out of – without the Cotton Valley sale, you’d probably be running out of cash sort of towards the end of this year. So do you think sort of the – if you get the Cotton Valley sale done and you get the 2013 subscribed, that’ll allow you to run a two-rig program through the first quarter of next year or sort of what’s your timeframe of when you got to come back – when you need another transaction and sort of what you’re thinking would be next? Would it be sell the Niobrara or what?

Michael Rohleder

Yeah. I think that’s a good question, David. My opening remarks were heavy on the word step. I think when you look at our transition, it’s made up of multiple steps. So I think the Cotton Valley is a piece of that, the potential of the Niobrara is a piece of that, a JV might be a piece of that. We’ve historically gone into the capital markets with the story of expansion acceleration. So I think getting the 2013 note resolution is an important first step to setting the stage for the rest of the steps.

David Epstein – CRT Capital

Okay. And if somebody asked this, I’m not sure what you said. So current flow rates out of Cotton Valley are about 11,000 Mcf, and is that right? And do we know what the PDPs are out of the Cotton Valley? And I’m not sure if you expressed how many of those you are selling.

Tim Benton

Yeah, the 11,000 Mcf is all PDP. Obviously, there is a PDNP component to that as well. I think it’s set out on the page four of the presentation.

Michael Rohleder

Yeah, take a look at page four of the deck, David. That’s the highlight of – and will probably give you most of the information you want to put it in your model.

David Epstein – CRT Capital

Thanks so much.

Operator

Thank you, sir. (Operator Instructions.) Presenters, at this time, I’m showing no additional questioners on the phone line. I’d like to turn the program back over to Mr. Alan Van Horn.

Alan Van Horn

Yeah. Thank you, Huey, and GMX Resources would like to thank all of you for attending our conference call and thank you for the questions that you asked. Feel free to visit our website and if you have any additional questions, feel free to contact me or one of the other speakers on today’s conference call. Thanks and have a great day.

Operator

Thank you. That does conclude today’s call. We appreciate your participation and you may now disconnect.

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