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Gastar Exploration Ltd (NYSEMKT:GST)

Mid-Continent Transaction Conference

April 01, 2013 10:30 am ET

Executives

Lisa Elliott - Principal

J. Russell Porter - Chief Executive Officer, President and Non-Independent Director

Michael A. Gerlich - Chief Financial Officer, Principal Accounting Officer, Vice President and Corporate Secretary

Analysts

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Patrick B. Rigamer - Iberia Capital Partners, Research Division

Kim M. Pacanovsky - MLV & Co LLC, Research Division

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Stephen F. Berman - Canaccord Genuity, Research Division

Chad L. Mabry - KLR Group Holdings, LLC, Research Division

Joshua D. Young - Young Capital Management, LLC

Operator

Good morning, and thank you for standing by. Welcome to the Gastar Exploration Conference Call. [Operator Instructions] As a reminder, this conference is being recorded today, April 1, 2013.

I would now like to turn the call over to Lisa Elliott of Dennard Lascar. Please go ahead, Lisa.

Lisa Elliott

Thank you, and good morning, everyone. Before I turn the call over to Russ Porter, I do have a couple items to go over. First, management will be referring to some maps and other graphics during this morning's call and you may want to take a moment to go to Gastar's website and find this presentation at www.gastar.com in the Investor Relations section under Events and Presentations, as well as from the IR homepage. The PDF of the slides is adjacent to the webcast link for the call.

Also, a replay of this call will be available shortly by webcast from the company's IR website and a telephone replay will be available for 1 week. The information you need to access the replays is in today's press release.

And finally, today's call will contain forward-looking statements as referred to on Slide 2 of the presentation on the website. And although management believes that these statements are based on reasonable expectations, they can give no assurance that they will prove to be correct. These statements are subject to certain risks, uncertainties and assumptions as described in the company's 2012 Form 10-K and which also can be found in the Investor Relations section of the website. Should one or more of these risks materialize or should underlying assumptions prove incorrect, actual results may vary materially.

Today's call may also include extension of probable or possible reserves, to use terms like reserve potential, upside or other descriptions of non-proved reserves, which are more speculative than estimates of proved reserves and accordingly, are subject to greater risk. Information relayed on this call speaks only as of today, April 1, 2013, so any time-sensitive information no longer be accurate at the time of the replay.

Now I would like to turn the call over to Russ Porter, Gastar's President and Chief Executive Officer. Russ?

J. Russell Porter

Thanks, Lisa, and good morning, everyone. Also with me this morning is Mike Gerlich, our CFO.

I'd like to begin with an overview of the transaction in this new play, including our preliminary development plans then cover details of the valuation and our plans for financing the transaction. We're very pleased to announce our acquisition of a large package of highly perspective oil acreage in Oklahoma from Chesapeake Energy. This acreage is located in and around the Mid-Continent oil play acreage that we've been building a position in for the last 1.5 years.

As you see on Slide #3, the aggregate consideration for the transaction is $85 million. That assumes a cost of about $41 million for the undeveloped lease acreage and $33.2 million for the developed and producing acreage. Also, as a part of the transaction, we are repurchasing all of the common shares that Chesapeake Energy owns in our company, which is almost 10% of our shares outstanding, for roughly $10 million at a price of $1.44 per share. This accomplishes a 10% stock buyback at a price that is materially lower than where our shares were trading prior to the Chesapeake litigation.

In addition, all litigation between Chesapeake and Gastar will be dropped. We have assigned $1 million of the $85 million transaction value to settlement of the litigation, which is approximately our estimate of future costs, if we were required to prepare for and execute a defense at trial. We expect to close the transaction by June 7, with a property purchase effective date of October 1, 2012.

Now that we have this extensive acreage position, we can finally disclose more information on our Mid-Continent oil play, where we've just finished drilling our fourth well. As you can see on Slide 4, we've previously been pursuing the horizontal Hunton Limestone play in Major, Garfield, Blaine and Kingfisher counties in North Central Oklahoma. Our existing acreage is highlighted in yellow.

With this latest transaction, highlighted in green on the map of Slide #4, we gain a large acreage position in Kingfisher and in Canadian counties to the South and East of the area of mutual interest we established with our existing Mid-Continent operating partner in 2011. This transaction and the Hunton oil play have the potential to be a game changer for Gastar, in the same way that our entry into the Marcellus 3 years ago was a transformational event for our company. Our confidence in this play is based on the results of drilling inside and outside our AMI, and is underscored by the outstanding results of our second well on our existing acreage.

On Slide 5, you can see details on the Mid-Con 2H well. As we mentioned in our last earnings call, we learned quite a bit from our first well in Hunton, and with the second well, we have refined the placement of the lateral within the formation and optimized completion techniques to achieve substantially improved results. Mid-Con 2H well began producing on February 15 and is currently producing at an average daily rate of 968 barrels of oil equivalent per day, of which 87% is crude oil. Our original expectation for this well was oil production at a stabilized rate of about 400 barrels a day after recovery of a large portion of the completion fluids. We're seeing over double that rate already with very little of the completion fluids recovered.

Expanding our Mid-Continent acreage further reduces our dependence on dry gas and it increases our exposure to crude oil, which carries better pricing and economics than the NGLs and condensate that have made our Marcellus Shale operations in West Virginia so attractive in today's commodity price environment. This acreage offers a large inventory of repeatable, oil-rich drilling prospects that should keep us actively drilling for many years ahead.

If you'll turn to Slide 6, I'll go through the detailed description of the assets we're acquiring. The acquisition includes drilling rights from the top of the Mississippi Lime and deeper on about 157,000 net acres in Kingfisher and Canadian counties. About 71,000 acres is in what we call our Tier 1 area, where we are targeting the updip pinch-out of the Hunton Limestone using horizontal drilling. To orient you on the formations, the Woodford formation is directly below the Mississippi Lime and the Hunton is just below the Woodford. Later, we could find that the Mississippi lime and Woodford are commercially productive, but right now we're not giving any value or consideration to those zones.

Also included are 176 producing wells, half of which will be operated by Gastar and 19% of the overall acreage we're acquiring is held by production. Current daily production is approximately 177 barrels of 40 degree API gravity crude oil, which sells at a slight premium to WTI, along with 54 barrels of NGLs and 3.5 million cubic feet of natural gas per day. This long-lived production, as well as the undeveloped acreage, has ready-access existing pipeline and processing infrastructure in Central Oklahoma. Currently, these producing wells deliver 500,000 to 600,000 per month of cash flow. There's a possibility that with relatively modest capital investment, primarily for additional compression, we may be able to increase average daily production from these wells. Our primary focus is on drilling the undeveloped acreage, so any increase in existing production will be a nice bonus but immaterial compared to continued new horizontal development of the play.

Net proved reserves associated with the 176 wells include approximately 494,000 barrels of oil, 271,000 barrels of NGLs and 12.5 billion cubic feet of natural gas for a total of 2.8 million barrels of oil equivalent. These reserves are all classified as proved developed producing, their PV-10 value is $32.3 million based on the NYMEX strip as of March 8, 2013.

As I mentioned a moment ago, our excitement about the Hunton play is based not just in our own limited experience with the wells we have drilled and completed today, but also on 13 other wells that our JV partners drilled in the play over the last couple of years. As you can see in the bottom half of Slide #7, the last 7 Hunton horizontal wells drilled in the area by our operating partner have realized an average peak rate of 645 barrels of oil equivalent per day, with internal estimated gross reserves of 436,000 barrels equivalent per well. If you compare that to the first 6 wells, clearly, the results are improving as we climb the learning curve. So we think there is upside beyond these initial results, both in terms of well performance and research -- and resource potential based upon our own Mid-Con 2H well.

Looking at the top half of Slide 7, we showed you the status of Gastar's Hunton wells. We're currently commencing flow back on well #3H, and we expect initial production later this month. The design of 3H well is similar to the 2H with an 8,000-foot vertical depth and 4,300-foot lateral, and we're using the same completion techniques. We spudded Mid-Con 4H well in mid-February, and it is waiting to be completed. We expect to bring it online in the middle of the second quarter.

Drilling and completion cost is about $5.2 million per well. As with any play, once you gain experience, you're generally able to refine drilling and completion methods to prove up more reserves, optimize average daily production and assuming stable service cost, do all that in an increasingly lower cost per well. That's been our experience in both the Marcellus Shale play and in the deep Bossier play.

The way we see this, we have excellent results about 30 miles apart along the geologic trend. This acquisition adds a lot of acreage between those 2 successful areas. There are successful wells that book into play proving, in our opinion, the concept. We like our chances that the acreage we're adding along the trend and between the successes will also be good. If we're right, we have many, many years of drilling and substantial oil resources to develop.

With this acquisition, we now have over 250 net potential drilling locations in our Mid-Continent play that exposes us to more than 100 million BOE of net resource potential. This includes 65 locations on our existing acreage and over 200 net locations on the Tier 1 acreage we're acquiring from Chesapeake.

As you can see on Slide #8, in 2013, we currently plan to drill a total of 12 wells in the Mid-Continent area, including 4 operated wells on the new acreage and 8 non-operated wells with our partner in the existing AMI. We expect the first well in this new acreage to be spud sometime in the third quarter. Our expected capital spending for drilling and completion in the Mid-Continent overall, excluding lease acquisition, is $37 million this year or an incremental $11 million compared to our earlier announced 2013 capital program. That CapEx amount could be reduced if we bring in a joint venture partner on our new Mid-Continent acreage late this year, which would leave us with a lower net working interest, as well as potentially carry drilling and completion cost.

Next year, we plan to drill and complete 8 non-operated wells with our partner in the existing AMI and 16 operated wells on the new acreage. These wells are preliminary, these plans are preliminary and subject to change depending on our success in the play and our access to capital. Our capital requirements will depend on the terms of any potential joint venture that we may form with respect to the new acreage.

This drilling program in the Mid-Continent play will have no impact on our 2013 Marcellus program, where we plan to spend approximately $60 million to drill 9 gross wells and plays on production an additional 19 gross or 9.5 net operated horizontal Marcellus Shale wells in the risk gas window in Marshall County West Virginia.

Turning to Slide 9, we plan to finance the transaction using the proceeds from a potential sale of our East Texas assets and the issuance of debt or preferred stock. As we have previously stated, we've been seeking a buyer for our East Texas producing properties, and we're optimistic we will finalize a transaction in the very near future. This will give us cash to apply towards the Chesapeake transaction, but also reduce the capacity of our revolving credit facility due to a slightly smaller proved reserve asset base. If we're successful, we estimate the net gain on liquidity from the sale of East Texas would be about $25 million. We're currently exploring options for raising $100 million to $200 million in debt and/or preferred equity financing. We do not intend to issue any common equity to finance this deal.

We're also beginning talks with potential joint venture partners for the additional Mid-Continent acreage, which would allow us to reduce our debt level following the close and help us fund our planned exploration and development program in the Mid-Continent. This would likely take the form of upfront cash to reduce our net debt plus the drilling carry. Our existing partner in the original AMI area has the right to participate and operate any of the acquired acreage that falls within that AMI area, which is approximately 20,000 net acres or 10,000 acres net to our existing partner. Our goal will be to close the JV agreement for the new acreage before the end of this year.

Like many other small E&P players, Gastar has undergone a lot of change in the last 4 or 5 years, and most of that change has been driven by the shift in economics in the natural gas business. The one thing I'm proud of is that Gastar has been successful in staying ahead of the curve by transitioning our portfolio of assets. We've taken substantial early positions in developing plays with wet gas or crude oil at a low cost, and we've positioned ourselves in the best and most profitable parts of the plays. Even in the face of capital constraints due to lower commodity prices, we've continued to grow reserves, grow production, grow the profitability of our activities and grow the value of our asset base. The latest transaction, the Hunton oil play, I believe, is a giant step forward along our strategic path to creating value for our shareholders.

As you can see on Slide 12 -- excuse me, Slide 10, this transaction expands our exposure to what we view as an extremely perspective horizontal oil play with excellent resource potential and economics. It increases our inventory of low-cost, high-return, repeatable drilling locations, and exposes our company to an excess of 100 million barrels equivalent of resource potential, primarily crude oil. I would stress that this is not a chasing oil transaction, this is a bolt-on acquisition to geologic and engineering work that we've been doing for over a year. It's serendipitous in that it also settles the Chesapeake litigation, but as a standalone acquisition, we still love it. Neither is it a late-stage grab for oil. We like the economics of the deal and we like that it makes us a more balanced company in the form of commodities.

This should not be construed as we are moving away from natural gas. We're still constructive on the rebound in natural gas prices and we have exposure there. Our natural gas growth is in an area of low-finding cost and economic in today's prices. This acquisition adds oil exposure with what we expect to be attractive returns. We are very cognizant of the current high oil prices and we'll continue to lock in these returns with hedges as these barrels are found.

Although this transaction is all about growing our opportunity within the Mid-Continent oil play, it also removes the overhang of Chesapeake's large ownership position in Gastar's common shares, as well as a distraction and the overhang of potential future litigation cost of lawsuit, which has weighed on our share price over the last several quarters. This is an exciting, high-impact opportunity and an exciting time to be at Gastar. The additional Oklahoma acreage is a potential game changer. We expect it to generate substantial new shareholder value over the next several years.

With that, we've finished our prepared remarks and we'll take questions at this time.

Question-and-Answer Session

Operator

[Operator Instructions] And our first caller this morning is Ron Mills with Johnson Rice.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

A couple of questions for you though on the acreage. You highlighted 71,000 acres of the 157,000. If you look at the map on Page 4, can you kind of direct us to where those 71,000 acres are that you considered Tier 1? And is that also -- when you talked about 19% of it being held by production, is it just of the Tier 1 or is it the total package? And what's that exploration schedule like?

J. Russell Porter

It's 19% of the total package. I'll let Mike give you some details on the exploration schedule in just a moment. We personally didn't highlight yet that Tier 1 area because we are still cleaning up some things in that area. But as I described it, it's along the updip pinch-out of the Hunton Limestone play there. So as we get a little bit more mature with the lease position and get some of these renewals and extensions under our belt, we'll provide additional information on exactly where that Tier 1 area lies.

Michael A. Gerlich

And Ron, in regards to your question about HBP, there's just under 10,000 acres or roughly about 14% of that Tier 1 acreage held by production. As Russ alluded to the explorations, there are some near term, particularly focusing on 14 explorations, about 65% of that acreage is subject to expire, but just under 60% of it has automatic lease extension kickers, which we obviously have factored into our valuation.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

60% of the 65% or they're 60% of the total?

Michael A. Gerlich

65% of the 71,000 net acres. There's 48,000 acres expiring in '14 and of that, about 28,000 has automatic kickers to it.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay. Good. And then my follow-up would be the Mid-Con 2 well and what you're doing with 3 well. It sounds like you targeted the lateral in a different portion of it. That updip pinch-out that you talked about, is it just -- I guess, I'm trying to get a sense where the aerial extent of that because it -- and when you talk about the 250 locations that -- I want to make sure that just comes from your existing AMI plus the Tier 1 acreage?

J. Russell Porter

That's right, Ron. Existing AMI in Tier 1 acreage have that number of locations that we've quoted in the prepared remarks. The play extends beyond our acreage position. The play itself we think encompasses probably about 0.5 million acres. So we've got a nice position in it. But by no way have we -- by no means have we captured the entire play or anything like that. But like I said, we'll provide additional detail on Tier 1 area once we have a chance to digest these new acres, get a handle on what we're going to drill, what we're going to extend, and what we need to be out renewing in the market.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

And one more if I can. On the drilling plan you highlight, you talked about 12 total wells this year, 4 on the new acreage and 2 net. Are you already assuming that you're going to do a 50-50 JV to get down to 2 net wells versus the 4 gross and how is that factored into the $11 million CapEx increase?

J. Russell Porter

That does assume we bring in a 50% JV partner and the $11 million makes the same assumption.

Operator

Our next question is coming from Patrick Rigamer at Iberia Capital.

Patrick B. Rigamer - Iberia Capital Partners, Research Division

I just wanted to, I guess, follow-up a little bit. It sounds like you're landing the lateral on the second well a little bit lower, but are you doing anything differently from a completion standpoint relative to the first well?

J. Russell Porter

Just more stages. We essentially doubled the number of stages in the second well. And that, along with the placement of the lateral into a section that has more natural fracturing, it allowed us to get, as you can see, much, much better results.

Patrick B. Rigamer - Iberia Capital Partners, Research Division

And it's about 4,500 lateral length on the wells?

J. Russell Porter

Correct.

Patrick B. Rigamer - Iberia Capital Partners, Research Division

And about how many frac stages?

J. Russell Porter

In the most recent well, I think 23 stages.

Patrick B. Rigamer - Iberia Capital Partners, Research Division

23 stages, okay. And then, I guess, can you talk a little bit about some of the risking in spacing assumptions that go into those 250 location estimate?

J. Russell Porter

We've assumed that's 320-acre well spacing.

Patrick B. Rigamer - Iberia Capital Partners, Research Division

Okay. Any early thought on whether or not that can be down-spaced potentially or...

J. Russell Porter

No. We hope that it doesn't. We hope that we're effectively draining that large an area and we can get out these reserves with the number of wells we expect now. But at some point, there'll be some down spacing because there'll be some areas where we can't control an entire 320 or an entire 640. So it possibly can get down spaced, but I think that using the assumption that there's between 250 and 275 net locations now and over 400,000 barrels equivalent EUR per location, gives us a pretty attractive asset.

Patrick B. Rigamer - Iberia Capital Partners, Research Division

Okay. And then just last one, quickly. I know you had discussions with the bankers on this, is there any incremental borrowing base with the production you're acquiring or...

Michael A. Gerlich

We'll be having those discussions shortly. But based on our internal valuation, we would think the PDP aspect using the bank's pricing would probably give us about $15 million in additional borrowing capacity.

Operator

And our next question comes from Kim Pacanovsky with MLV.

Kim M. Pacanovsky - MLV & Co LLC, Research Division

Talk about killing 2 birds with 1 stone, Russ. I just have a couple of questions. Are you seeing anybody else in the region drilling horizontally or is that just you and your partner at this point?

J. Russell Porter

There are some other private players that are in the area that have not been as active as we have and our partner has, but -- that have decent-sized lease positions and look like they're just trying to kind of catch on to what we're doing and their results are starting to improve.

Kim M. Pacanovsky - MLV & Co LLC, Research Division

Okay. Is there any advantage to data sharing with them to kind of define the sweet spot of the play? Or do you feel like you're just way ahead of the curve as compared to them?

J. Russell Porter

I think we're pretty far ahead on how to drill and complete these wells. And so we're -- with this transaction, the big landgrab, if you will, is sort of completed. But of course, we're always going to need to fill in and renew and extend some leases that we don't have the kickers on, so we're not going to be real generous with information yet.

Kim M. Pacanovsky - MLV & Co LLC, Research Division

Okay. And it looks like you have some rich gas as the development of the area ensues; would you see any issues with NGLs?

J. Russell Porter

No. There's great infrastructure in place now, plenty of processing capacity, so we're not anticipating any sort of midstream issues.

Kim M. Pacanovsky - MLV & Co LLC, Research Division

Okay. And finally, could you just give us a little bit more color on the status of the JV discussions and did these discussions start? I don't know how long this whole Chesapeake deal has been in the works, but did they start when you started feeling like you were well on your way to inking this deal with Chesapeake?

J. Russell Porter

We have some existing relationships and those folks have expressed interest in expanding their relationship with Gastar. We've also been approached by other operators who are looking for resource-type JVs and other financial -- more financial based partners or potential partners. So there's a good number of people that have expressed an interest. We're beginning those discussions now, and I really can't add much more than that.

Operator

And our next question comes from Neal Dingmann with SunTrust Robinson.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Just a question, Russ, as far as the midstream success on that well going forward, I guess, on the new play, will that kind of determine how much you spend on the Marcellus next year given -- it sounds like you don't have HBP issues on either plays?

J. Russell Porter

Our [indiscernible] continued in the Marcellus with factor drilling [indiscernible] next year than we have in 2013. As you might recall, we're taking a break from drilling in the Marcellus, really, for the second half of this year, so we can let the midstream assets catch up with our productive capacity. So as things stand right now, we project resuming drilling in early 2014 on the Marcellus and continuing to develop that asset.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

And then Mike, where do you come from if you don't get a JV partner, would you just scale down what you drill in the Mid-Con next year or just an idea as far as trying to stay within capital, I guess, is my last question?

Michael A. Gerlich

I think we'd look at our total capital expenditures, as somebody had mentioned, we don't have near-term lease expiration issues up in the Marcellus. We can maybe change our drilling approach from doing all the wells on a pad to focusing more on HBP, which would free up some capital for us. But again, it's early to decide what we're doing.

J. Russell Porter

And Neal, I just kind of remind you and everybody else, our history of joint ventures going back to -- we brought in a joint venture partner in the Powder River Basin for the coalbed methane play. We brought in a joint venture partner in Australia for that play in New South Wales. We brought in a joint venture partner in East Texas. And we brought in a joint venture partner in the Marcellus. So I think we've got a pretty good track record of capturing the type of assets that are attractive to people and being able to structure and close those type deals.

Operator

And our next question this morning comes from Steve Berman with Canaccord.

Stephen F. Berman - Canaccord Genuity, Research Division

Two questions, Russ. What are you getting for your oil there relative to WTI and how are you getting it out of there? And then secondly, when you drill down to the Hunton, have you taken any course on either the Miss Lime or the Woodford and of course, the logs and if you have, can you share anything you've seen there?

Michael A. Gerlich

Steve, this Mike. In regards to your pricing question, basically, what we're seeing out there is a posted plus to WTI of about $1 per barrel.

J. Russell Porter

And then with regards to the Mississippi Lime and the Woodford, there has been some activity. Chesapeake had drilled a couple of Mississippi Lime wells with not great results, but there is some other activity in the Mississippi Lime in this area. There's also been some Woodford activity and yes, this appears to be on the very rich portion of the Woodford. But like we said, we've been very focused on the Hunton and we haven't given any value to those other formations. So maybe that outside our Tier 1 area, there are some areas that would be attractive to other operators so we're not going to rule out the possibility of farming out some of that or even selling it at some point in the future. But we really want to capture this, get our arms around it, evaluate it before we decide to make any of those type moves.

Operator

Our next question this morning comes from Chad Mabry with KLR Group.

Chad L. Mabry - KLR Group Holdings, LLC, Research Division

Looking at the EUR, it looks like you kind of nudged up your expectations there to that 430 MBOE and I guess drilling and completion costs of about 5.2 gross, which both are above kind of previous figures. Can you kind of help walk us through what drove that increase that mainly based on these last 7 wells in Logan and Kingfisher counties there? And then, I guess, is the well cost more a result of kind of doubling those frac stages? I guess any color would be appreciated.

J. Russell Porter

The well cost is primarily due to increasing the number of frac stages. As far as the EURs, we're basing the type curve on the last 7 wells that were completed. That excludes our most recent 2H well, which if you included it would skew that average upwards, so it's based on wells that we got as long as 18, 19 months of production history, so they're pretty well-established decline curves that we're using to judge these EURs.

Chad L. Mabry - KLR Group Holdings, LLC, Research Division

Okay. And then is your commodity split there is still kind of in that 43% gas, 57% liquids range?

J. Russell Porter

It is. But as you'll noticed, our most recent well is almost 90% oil. So I think in different areas you're going to have a little less gas, a little more gas, but our type curve does use the numbers that you mentioned.

Operator

And our next question comes from Josh Young at Young Capital.

Joshua D. Young - Young Capital Management, LLC

So question on the East Texas potential sale. Can you talk about how much borrowing base you currently have from that asset and where you're at in that process?

Michael A. Gerlich

The last indication we got from our bank group is that roughly about $20 million of our current borrowing capacity of $125 million was ascribed to our East Texas assets.

Joshua D. Young - Young Capital Management, LLC

Okay. Great. So if you were adding an additional $20 million of liquidity from selling some of that asset, you're kind of implying potentially around $45 million or so potential sale price from that asset?

Michael A. Gerlich

That's correct.

Joshua D. Young - Young Capital Management, LLC

Okay. And then, what form of financing are you guys looking at to finance this deal? So I guess assuming the Texas sale doesn't close and the borrowing base only increases by $15-or-so million felt from this acquisition, I mean, it looks like there is a gap. Are you looking at some kind of like high-yield offering or preferred offering or how do you think about that and what's the market look like for that type of issuance?

J. Russell Porter

Josh, right now like we said, we're looking at raising $100 million to $200 million in either the high-yield or the preferred equity market. The lawyers are on us about not saying very much about that at this time, but we've got multiple proposals and it looks like the market is very open for this type of transaction. So we're very confident in our ability to finance it and to finance it in a way that allows us to move forward with the capital we need and on our projections, generating very good results.

Joshua D. Young - Young Capital Management, LLC

That's great. And one more follow-up. When do you expect to be able to share results on this third well?

J. Russell Porter

We'll actually start flowing it back later this week. So I'd say probably 3 or 4 weeks after that we'll have it cleaned up and have sort of indicative rate on it. So as we go out and start talking about financing, there's probably when we'll issue additional information.

Operator

[Operator Instructions] And our next caller, we do have a follow-up question from Ron Mills with Johnson Rice.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Russ, on the existing production in reserves, the 2.8 million barrels and 800 BOEs per day, what zones is that production and reserves coming from? Is it from the Mississippi Lime? Is it from the Hunton? Is it varied?

J. Russell Porter

It's varied. It's from Hunton, Mississippi Lime, primarily, vertical wells. There's a handful of horizontal wells in there, but it's almost all old vertical wells.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

And I think you or Mike mentioned earlier that the monthly cash flows I think you said is $500,000 a month, is that based on the current production or I missed that comment?

Michael A. Gerlich

Yes. That's just what the current production is kicking off.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay. And from a drilling, I guess, program standpoint. If you start drilling in the third quarter prior to getting a JV done, how would you think about having 100% of the cost in some early wells and how can that be structured into the JV?

J. Russell Porter

We are not worried about having 100% of the cost in some of the early wells. And the JV will be structured on a go-forward basis whenever they decide to come in, they buy into what we have remaining at that point, and it would be a negotiated discussion on whether they buy into the recent drilling or the existing production.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay. And then 2 more quick ones. In the Mid-Continent again, you talked about drilling in the middle or lower Hunton versus the upper Hunton. Technically, what are some of the differences? It sounds like it may be more naturally fractured. Is that the primary driver or is there something else beyond just the natural fractures?

J. Russell Porter

Yes. We're targeting a lower section because we see more fracturing there. We're staying away from some of the areas where you've had, in the upper Hunton, where you've had matrix porosity and those have been drained with vertical wells. So we're staying away from those and we're concentrating on the areas where we think we got better fracturing.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

And then just shift to Marcellus for one second. I know there was that pipeline rupture, but it seems like you've had minimal impact from that. Can you just provide an update there?

J. Russell Porter

Yes. I talked to the guys up there this morning that we ran throughout the weekend with really no interruptions. Lime pressures are a little high, but other than that we haven't seen any detrimental effect from the recent pipeline incident and it sounds like Williams may actually get in there and start repairing that line later this week. So hopefully, in a couple of weeks we'll be back to sort of the normal operating mode.

Operator

At this time I'm going to turn it back over to Russ Porter. Russ?

J. Russell Porter

Okay. Thank you. I appreciate everyone joining us this morning. As usual, if you have any additional questions, you can feel free to contact myself or Mike here at our office. And we thank everyone for your continued interest in Gastar. Goodbye.

Operator

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