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Executives

Alan Van Horn - Manager of Investor Relations

Michael J. Rohleder - President and Director

Ken L. Kenworthy - Co-Founder, Chairman and Chief Executive Officer

Nicholas Sommer

James A. Merrill - Chief Financial Officer, Principal Accounting Officer, Treasurer and Secretary

Harry C. Stahel - Executive Vice President of Finance

Analysts

Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

David Snow

GMX Resources (GMXR) Q3 2012 Earnings Call November 8, 2012 9:00 AM ET

Operator

Good day, ladies and gentlemen, and welcome to the Third Quarter 2012 GMX Resources, Inc. Earnings Conference Call. My name is Kathleen, and I'll be your operator for today. [Operator Instructions] As a reminder, this conference call is being recorded for replay purposes. I would now like to turn the conference over to your host for today, Alan Van Horn, Manager Investor Relations of GMX Resources. Please proceed.

Alan Van Horn

Thanks, Kathleen, and good morning, and welcome to our third quarter earnings conference call. We appreciate, as always, the participation of our shareholders, as well as brokers, analysts and friends. Today, we plan to review the accomplishments we achieved in the third quarter and first 9 months of 2012. On the call for GMX this morning are Ken Kenworthy, Jr., Chief Executive Officer; Michael J. Rohleder, President; Jim Merrill, Chief Financial Officer; Dr. Nick Sommer, Senior Geoscience Consultant; Harry Stahel, Executive Vice President of Finance; and Darrel Hardy, our Controller. During this call, we’ll review our results for the third quarter during 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 1 hour after its completion. Both the conference call with an accompanying slide presentation and our third quarter 2012 earnings release can be found on our website at www.gmxresources.com.

Before we begin, I want to remind everybody 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 November 7, 2012, announcing our earnings as well as disclosures in our public reports on Forms 10-K, Q and 8-K filed with the SEC and available on the SEC EDGAR website, as well as on our 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 and in our webcast slides. At this point, I'd like to turn the call over to Michael Rohleder. Michael?

Michael J. Rohleder

Thanks, Alan, and good morning, everyone. I appreciate you joining us on the call, and I am going to be using the slide deck that Alan referenced, that's available on our website for this part of the presentation. I hope to navigate quickly through it and leave lots of time for questions and answers.

So let's begin on Page 3 of the presentation deck, which is really a summary of our actions, activities and expectations related to the 3 focus areas for the company. Specifically, liquidity, execution and growing our net asset value. This morning, we're pleased to report that we have crafted a solution that we think addresses the remaining balance of the 5% notes due in February 2013, and I'll give a little more detailed explanation here in a moment.

We were successful in selling our East Texas Cotton Valley Travis Peak assets for $69 million. And we told the market that we would sign an agreement by the end of Q3, we actually signed that on October 1 with a closing date scheduled for October 24, and we did in fact announce the closing and funding of this sale on October 24. So this sale provides a liquidity to fund us into 2013.We've also called for a special meeting for shareholders scheduled for November 29 to vote on a proposal to give our Board of Directors the discretionary authority to affect a reverse stock split.

The NYSE requires listed companies stock price to trade above $1. In any event it doesn't, for a period of 30 days, those companies risk delisting. An obvious cure would be for the stock to trade above $1 and another cure to avoid delisting is to initiate a reverse stock split. We also know that certain institutional investors are prohibited from investing in companies whose stock trades at less than $1. And assuming a positive vote, any decision by our board to call for a reverse split will take into account these factors and also the prevailing market conditions.

We've achieved a significant reduction in our G&A this year, and we are on track to achieve the forecasted 20% reduction. We'll continue to seek additional sources of capital to fund our drilling programs, and our longer-term objective is to position the company to be able to eliminate or attractively refinance our long-term debt.

The first of our 2 fourth quarter wells has been successfully brought to sale. The Akovenko 24-34-2H was our first well drilled using oil-based mud and completed using a plug and perf methodology with ceramic profit. The IP rate of 3,029 boe per day is a testament to the progress we've made and a down payment on the promise of our future. The Akovenko 2 IP rate was twice as good as a direct offset Akovenko 1, and the production flow has doubled our daily production rate.

The Basaraba, completed in late September, has a 30-day average of 540 BOE per day; and the Lange 1, our best well to date, has been reviewed by our reserve engineers and its EUR has now been upgraded to 560,000 BOE, which is above our published average of 505,000 BOE. And the Lange 2H, which will be a direct offset to that well, has been drilled and it's expected to be completed and producing in mid-December.

We highlighted on our Q2 call in August, and a number of presentations during the third quarter, that we have a number of changes intended to implement in our drilling and completions in the Bakken, and the Basaraba and the Akovenko 2 are two outstanding examples of how those changes have made a significant difference. We intend to drill our first Niobrara test well in the first quarter of 2013 using the guidance provided by our 3D seismic analysis. A number of operators are reporting significant wells in other parts of the DJ Basin in the Silo Field, just south of our position, provides the best example of possibilities in our part of the play. The opportunity to prove the Niobrara will have a significant impact on the net asset value of the company.

And finally, our focus is on growing the net asset value through the development. The 1-rig program in the Bakken which is projected to yield 2,000 BOE per day by November of 2013 could inherit to a $700 million value if the same transaction metrics of recent McKenzie County deals are applied to our pro forma production and expected undeveloped acreage. Additionally, with the successful execution in the Niobrara, our recovery natural gas prices and future expansion of our Bakken development, we're in a position to see our NAV growth dramatically over the next several years.

On Slide 4, we announced, today, new capital providers, including the Blackstone Group and certain holders of existing first lien secured notes of the company who have signed commitment agreements with respect to financing commitments that will result in GSO Capital Partners becoming a beneficial owner of approximately 7% of the common equity of GMX Resources, and to continue to be the largest debt holder of the company. As part of this new relationship, we expect to issue a new first lien secured note in which the proceeds will be used to retire the remaining balance of the 5% notes.

We're very pleased to expand our relationship with Blackstone/GSO. They are a long-term investor who shares our vision for generating value and upside from high quality assets, and they have a track record of support with a variety of companies such as Cheniere Energy, Chesapeake, Saratoga Resources and many others. I know it's not lost on many of you what having a financial partner of this magnitude invest in the equity and debt of the company means.

On slide 5 is a recap of our successful Cotton Valley Travis Peak sale. Importantly, we regain all of our Haynesville/Bossier rights, as well significant opportunity in the remaining Cotton Valley acreage. You can see the pro forma impact of the sale, as well as a host of metrics on the sale, allowing you to evaluate this, as well as update the models.

On Slide 6, retrospectively, we could characterize our first year of development in the Williston Basin into 3 distinct phases. We started our development in July of 2011 when services were largely unavailable. Our first 2 wells targeted Three Forks and were completed using a 15-stage RapidFrac sliding sleeve system. We restricted our well flow, and because of lack of services we're unable to clean out our wellbores, and we averaged about 150 BOE per day.

In our second phase, we begin to target the Middle Bakken and increase the number of stages from 30 to 40 using a more traditional sliding sleeve technology. We're still challenged with post-completion equipment availability, and because of a lack of consistent electrical power, experienced a higher percentage of downtime on producing wells, but our results did increase quarter-to-quarter and we averaged over 400 barrels of oil per day.

In the third phase, where we are now, we are averaging almost 1000 BOE per day and we've made many changes including focusing on the Middle Bakken exclusively, changing to plug and perf completions and developing an entirely different flowback protocol. We have access to all the services we need on a timely basis, and we solved our need for more reliable power sources to keep our pumps running.

In our fourth phase, we look to continue to improve on execution just like we've done in every play we've been involved in, and we expect to capitalize on the learning curve and we'll continue focus on lowering cost and expect our well performances to continue to improve.

On Slide 7, we provide a recap on production and future guidance, as well as a graph showing you how quickly the Bakken NAV will grow on just the 1-rig program. By the end of 2012, we expect to be producing 1,000 barrels of oil per day, which would have an estimated NAV of about $500 million using the same transaction metrics from deals completed recently, in and around our acreage. That NAV jumps to $700 million by November 2013 as our production per day continues to grow.

Our fourth quarter '12 guidance is 75,000 barrels of oil, which is up 100% over third quarter, and in the first quarter of 2013, we expect oil production to be 680% above the first quarter '12 production. Bakken operated and non-operated crude oil production will be approximately 21,000 barrels in October, which is a 46% growth over September and, in fact, the month of October we've achieved a 56% of our third quarter production. The third quarter of 2012 can be viewed as a trough for production and revenue, and moving forward, we expect significant quarter-over-quarter and year-over-year growth.

Slide 8, we've updated the third quarter reserves and resource potential. Since year-end 2011, we've increased our oil reserves 4x. The estimated proved NAV is approximately $340 million. The resource potential for the company is enormous, with 133 million barrels of oil in the Bakken and Niobrara. Our Haynesville/Bossier is the #1 natural gas play and is a natural geographic fit for future LNG export facilities, and while we did sell a portion of our Cotton Valley, we've retain assets that could potentially have an NAV of $350 million. All of these high quality assets provide NAV growth opportunities.

On slide 10 gives you recap of our assets. We now have 14 gross wells in the Bakken. We've stated that our goal was to gain the flexibility of focusing on assets that would deliver the highest rates of return. We now have that flexibility. As we prove the commercial value of the Niobrara in 2013, and as natural gas prices improve, we will be well positioned to deliver high rates of return on all of these assets.

If you take a look at Slide 11, that provides a recap of some of these recent transactions in the Williston Basin. It gives us the confidence to say that our acreage is positioned in the center of the play. Not only are all of these transaction's valuing this part of the play, significantly more than the Statoil-Brigham transaction the was completed in 2011, that both Continental and Whiting consider all of this acreage as fully de-risked. This transaction-ology, along with our most recent well results, confirm our view that our acreage carries a similar value.

On Slide 12, our drilling focus is in these de-risked areas, and our acreage sits on top of known structures, the Little Knife, Little Missouri, Billings Nose, Saddle Butte anticlines run directly through our GMX acreage. You could see our 3 focus areas. The Teddy Roosevelt Grasslands in McKenzie County contains 8 operating units in 59 locations. In our Billings Nose extensional area, we expect to operate 15 units with 84 locations. And finally, in the Pronghorn, we expect to operate 4 units in 14 locations, and another 40-plus units have the potential to be operated in these 3 de-risk areas.

On Slide 13, the Williston Basin story begins here by understanding the Bakken petroleum system. It's a stacked play of fractured reservoirs. The Pennsylvanian Upper Devonian system begins at just over 10,000 feet and is approximately 400 feet thick. The system is overpressured, with a total organic content of approximately 11%, 6% to 10% porosity and has relatively low permeability. This system has 6 separate layers capable of production.

On slide 14 shows a very early Williston development. The first wells drilled in the early 50s were vertical Middle Bakken wells drilled on the Antelope Anticline in Northeast McKenzie County. Over a 22-year period, 47 wells were drilled. The next discovery occurred in the Billings Nose area, in Billings County, first with the vertical upper-Bakken shale wells, and then in 1987, the first horizontal upper-Bakken shale wells. The key takeaway from the slide is that the expansion you can, see along the Nesson and Little Knife anticlines, from Williams to Stark County and the beginnings of a big discovery in Richland County.

On slide 15, you can see the proliferation of the new wells occurring after the expansion of the play. In 1996, the Elm Coulee Field was officially discovered, and in 2000, first middle-Bakken horizontal wells were drilled in Elm Coulee. In 2006, the Parshall Field was discovered as a result of previous expansion. 1,428 wells were drilled in just 3 years. Again, note the expansion, beginning west of the anticlines, in Mackenzie; Williams; and Billings County, in North Dakota, as well as new expansion in Western Montana.

On slide 16, the Williston Basin is exploding with new development. Major expansion can be seen off the anticlines with the advent of modern drilling and completion technologies, and just the last 2 years, more wells have been drilled than in the previous 55 years combined. Again, note the continued expansion of the play.

And on Slide 17, you can see that the GMXR acreage is at the leading edge of the current expansion. Major operators in our area are developers of the middle-Bakken and the Three Forks. The Teddy Roosevelt National Park and Federal lands initially slowed down the development of Southeast Mackenzie and Northeast Billings County, but now there are many mature producing 1,280-acre unit surrounding our acreage, with recent completions exhibiting these EURs of 500,000 to 600,000 barrels, providing us proof that we can expect similar results. But the middle-Bakken is only half of the story.

On Page 18, the Three Forks is emerging as a significant component of many company's plans, and for us, it would be the same as we ramp up our development programs in the months and years ahead. Within the Williston Basin, the Three Forks development has been slower, but similar to the development of the middle-Bakken, in that the initial focus has been along the anticlines. We provide an isopach of the basin depicting the Three Forks thickness on this slide. GMXR acreage in Southeast McKenzie County has 250 feet of Three Forks.

On Slide 19, you could see that between 2005 and 2009, most Three Forks wells were drilled along the Nesson anticline. You also saw the Parshall Field and Sanish Three Forks development begin during this period. You can begin to see the expansion of the Three Forks in Lewis & Clark and the Billings Nose area.

On Slide 20, that expansion noted in the Billings Nose and Lewis & Clark can now be fully appreciated. In the last 2 years alone, over 700 Three Forks wells have been drilled. Operators have seen similar 30-, 60- and 90-day results in the Pronghorn and Lewis & Clark areas, as they had in the Sanish Three Forks results. Just as with the middle-Bakken development, operators are continuing to expand up the anticlines and will, over the next phase of expansion, claim the remainder of basin. While our current focus has been middle-Bakken, the Three Forks represents significant upside to GMX Resources as the Three Forks is more fully understood and the potential for up to 4 separate benches within the Three Forks are proved commercial.

So the Williston Basin story continues to evolve and we will continue to see improvements in our drilling efficiency, continued expansion of play throughout our acreage, experiments by other operatorsand ourselves in down spacing, and a greater appreciation for Three Forks in its role in achieving the increased recovery of the oil in place. GMX Resources is well positioned to capture the value of the Williston Basin and determined to deliver that value to our shareholders.

If you flip over to Slide 22, the best way to understand our Niobrara play is to understand the history of the Silo Field, which lies approximately 10 miles south of our 30,000-acre Bear Creek area. This map shows an outline of the Silo Field which has had 85 horizontal wells drilled in the early '90s. Now these are short-lateral open-hole single-stage completions. The green shading depicts an area that includes all the wells that have had a cumulative volume at least 100,000 barrels, and our wells that have had cumulative production of up to 500,000 barrels. The average of all of these wells is 230,000 barrels of cumulative production.

The blue overlay is from a 3D seismic study of the Silo Field and depicts the most intensely fractured areas of the Niobrara zone. We've identified 3 wells to demonstrate the importance of understanding where the joints and fractures are. The Francis Goertz is an example of a well that was drilled parallel to the fractures, and as a result, has only produced 33,000 barrels since it was completed in 1991. The Lemaster-State well, completed in 1992 and intersecting a large fracture system, has produced more than 500,000 barrels of oil. And the McConnaughey, as a final example of a well completed in 1992, that's a short lateral, but one that intersected the joint and factors in an intensely fractured area, and has produced over 440,000 barrels of oil.

On Slide 23, you can could see that we have over 300 square miles of seismic covering virtually all of our acreage, most of which is directly north of Silo. We have no doubt that the fracture networks necessary to be successful exist all across our acreage, and we believe, with modern completion technology, we will achieve results that should rival the best of Silo Field.

Our potential is revealed in the seismic which will allow us to determine specific placement to intersect the joints and fracture networks in the play. We're in the process -- permitting locations and currently plan to drill our first Niobrara test well in the first quarter of 2013. With a successful test well, we can begin to examine several options to continue the development. Another part of the chain of facts that gives us great confidence in our acreage is the fact that 85% of our acreage is within a 50-ohm contour and 100% is within 30 ohms. As we prove our thesis, the value of this asset will greatly increase and become a target for potential JV partners or an outright sale.

On Page 24, shown here, in a colorful way, are 2 different 3D seismic lines extracted from 2 separate wells. The first is the Lemaster-State well that I previously pointed the gap out. Again, that well has a cumulative production of over 500,000 barrels of oil to date.

The second example is from our own 3D seismic in the Bear Creek, and the location chosen is our first targeted location. In both the GMXR sample and the early Silo well, you can see a very similar pattern of intense fracturing indicated by the vertical, blue-green color swaths.

On Page 25 is a collection of Niobrara type curves. Our ultimate type curve can only be determined by drilling wells. We expect to be able to achieve results that are in line with those depicted here. What we are certain of is that the seismic signatures indicate abundant fracturing, and that 203 locations possess the geological setting that supports development. Other operators are reporting 45% to 85% rates of return, depending on the NYMEX price. So, for GMX, the Niobrara presents a significant upside potential.

On Slide 26, our Haynesville Bossier asset is currently not developing, but we want to remind you that we have over 1 Tcf completely held by production de-risked natural gas. At whatever point natural gas pricing allows comparable economic returns, the Haynesville will be very valuable asset to the company.

And then lastly, on Page 27, our Cotton Valley opportunity is shown. We have retained over 13,000 acres with an estimated 28 long horizontal locations, with 1,000-foot spacing and an estimated $7.5 million well cost, we expect to be able to achieve 7.5 B EURs.

On Page 28, why invest in GMXR now? Our oil production will grow significantly from this point forward. I consider our Q3 2012 as the trough of our transition to oil. We've selectively and strategically addressed the liquidity needs of the company through the successful sale of our Cotton Valley asset and the establishment of a key financial relationship with Blackstone/GSO Capital, and our operational improvements are demonstrating the success we've continuously forecasted. All of this will enable our assets to grow in value to the point where our Bakken assets alone will be valued at over $700 million. The Niobrara shows incredible promise and is being validated more and more every day by other operators, and our natural gas position in East Texas is an option on hundreds of millions of dollars of upside value. So with that Allen, I'll ask the operator to it open up for questions.

Question-and-Answer Session

Operator

[Operator Instructions]

Our first question comes from the line of Welles Fitzpatrick from Johnson Rice.

Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division

Can we get an update on the completed well cost post that H&P FlexRig coming in?

Ken L. Kenworthy

Yes, what we're seeing on the complete well cost is $9 million to $9.5 million. That includes the new plug-and-perf methodology and the ceramics. That's where we are, currently, on the well costs. I think, as we move forward, we're seeing some softening in prices out there, working with new vendors, and expect to drive those costs down below, I'd say, low 8's. As we move forward, I think if we went to pad drilling, there's probably $1 million of saving there per well.

Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division

Okay. And then in terms of the Niobrara, on the first quarter test, you said nearby Silo. Is that going to be in Southern Bear Creek? And is that going to be a horizontal or is it going to be more of science-type vertical well?

Michael J. Rohleder

It's going to start out as a science-type vertical well. We're actually going to take, I don't know, 200 or 300 feet of cord. Doc, what are you thinking?

Nicholas Sommer

Yes, we'll take a full core of 360 feet. We are members of the Core Lab Consortium for the Niobrara out there, and we will have to give them 2 cores from separate wells through to the Niobrara. So this first one will be partly science and then evaluate the logs in the core, and that will be redirected into a horizontal.

Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division

Okay. And one final one. Any furthering of the plans that you have? You guys have talked about, a little bit in past, of getting back into the Cotton Valley.

Michael J. Rohleder

Yes, I think we're still finalizing our CapEx for 2013. So we had originally messaged, I think the last time we talked to you, was that we maybe have a couple of Cotton Valley horizontal wells in the 2013 plan. I don't know that they'll still remain in the plan. It'll be very liquidity dependent.

Operator

And our next question comes from the line of Noel Parks with Ladenburg Thalmann.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Just a couple of things. The Akovenko well, actually, what time did that come online? Was it actually during the fourth quarter it came on?

Michael J. Rohleder

Yes. The well began producing this weekend. This last weekend.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Okay, great. Okay, so the current rate, is it fairly close to the test rate that you disclosed in the release?

Michael J. Rohleder

Yes. We produced at rates similar to 24-hour flows. I mean, it's only had a few days.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Okay, great. And in your forecast, for oil production, should be going forward. If I understood right, you were saying 2,000 barrels a day by November 2013. Is that barrels just for the oil component or is that going to be barrel equivalent, including whatever gas is?

Michael J. Rohleder

Yes. Sorry, that was BOE. I probably missed it when I said it originally, 2,000 BOE.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Okay, great. And actually, I did see the numbers you gave about the effect of the East Texas asset sale, just looking at my model. Where, roughly, should the company's gas production come out after the sale? I think I was looking at something in the sort of mid-teens million cubic feet, on the gas side. Does that sound like it's a right ballpark?

James A. Merrill

Right. I think what we got on Page 5 of the presentation and of the press release, it was on the effect -- the East Texas asset sale?

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Right.

Michael J. Rohleder

It's about 1 million a day.

Operator

[Operator Instructions] Our next question comes from the line of David Snow with Energy Equities, Inc.

David Snow

I'm wondering, in the new method of completion in that Bakken, with the oil-based mud, you referenced Brigham's playbook and papers, is that the way they -- or is that the standard way and the way they've been doing it?

Nicholas Sommer

We're not aware that they have been doing it, but others have done it in the past, and are currently doing it in our area. And Nick, and our petroleum engineer that worked on a core study, show that the impact of oil would soften the damage to the reservoir while drilling versus impact of water.

David Snow

Is this area specific or would you use it everywhere?

Michael J. Rohleder

Well, when you have an oil reservoir. It typically, in theory, works better.

David Snow

You're probably going to use it everywhere?

Nicholas Sommer

Yes. At this point, we anticipate using it everywhere.

Michael J. Rohleder

It actually turned out, David, to be more cost-effective than drilling with water-based mud. So there is an economic benefit to doing it also. But to Ken's point, our reservoir engineers have modeled it up and done a core study through the model that there's a technical opportunity, as well as an economic opportunity.

Ken L. Kenworthy

Yes. I would say what we're still evaluating whether or not we would continue to do this throughout the field. We've drilled 2 wells with it and I don't know that we've made a decision yet on the third well. But we'll see the results from the Akovenko, and then we'll have a chance on the line completion to see the results of that, although we are doing plug-and-perf versus sliding sleeve.

David Snow

You're using 100% ceramics?

Ken L. Kenworthy

No, it's half white sand and half ceramics.

David Snow

Okay. And then, I'm wondering, there was a well that GPOR drilled out in the Niobrara, that despite great seismic was disappointing. Did you pick up on that and you've got any reference point relative to that well of theirs?

Ken L. Kenworthy

Well, what we know is that we have seismic signatures, which is indicating significant fracture systems. We know that. The seismic is very good seismic. Nick, you can comment on this. And then secondly, we believe that our RT is high enough for oil generation to have taken place. So until we drill the well and intersect those fractures at the right azimuth, and see flowing oil, there's always a risk that the actual may not equal what we're thinking we're going to encounter and we see on the seismic. But our confidence level, Nick, is?

Nicholas Sommer

Our confidence in the seismic is extremely high, based off of modeling with other fractured areas using 3D seismic. As Ken said, until we put the drill bit into the ground, we don't know for sure, but the seismic is indicating extremely fractured areas, and the thermal maturity, based off of resistivity, is looking very good. It's equal to or better in some cases than Silo Field. If you go down and to Weld County, Carrizo is using a 25-ohm cutoff for their play. Ours is 30 ohms or better, so we feel very confident.

David Snow

Okay. And I'm wondering, the IP in that Bakken well. How did you measure that? Did you just take the first time you got a 24-hour good rate? Or what was the method?

Ken L. Kenworthy

David, we've been pretty consistent with how we've reported that from day 1 in all our Bakken wells. Those are peak flow rates. Initial peak flow rates.

Michael J. Rohleder

So it's the same measurement we've used with the previous Bakken wells.

David Snow

Actual 24 hours?

Michael J. Rohleder

No, peak rate.

David Snow

Not the 1 hour rate times 24?

Michael J. Rohleder

That's right.

David Snow

Okay. And then just lastly, how many shares are you issuing in this transaction? And what will be the fully diluted shares afterwards?

Harry C. Stahel

Yes, I've got that for you. The total shares that the GSO group will purchase will be just under 6 million shares, and then they'll also be purchasing restricted shares of another 10 million. So pro forma outstanding share count will be 96.3 million, and that excludes the 2.4 million of what shares that we'll have that's currently outstanding, that will be retired when we retire the 2013 notes.

David Snow

Okay. And what would be the next maturity that you have to meet after this?

Michael J. Rohleder

The 2015 right. I think that's October of 2015.

Harry C. Stahel

May.

Michael J. Rohleder

I'm sorry, May of 2015.

Operator

Thank you. I'm not showing any further questions at this time. I'd like to turn the call back over to Mr. Alan Van Horn for closing remarks.

Alan Van Horn

Thank you, Kate, and thank all of you for joining us for our third quarter call. And certainly, we're available, I'm available after the call, later today, if you have any further questions. Happy to take those calls, and again, thank you for joining us this morning. 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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