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Gastar Exploration (NYSEMKT:GST)

Q4 2012 Earnings Call

March 12, 2013 10:00 am ET

Executives

Anne Pearson

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

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

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

Hoshang V. Daroga - MLV & Co LLC, Research Division

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Nicholas Snyder

Operator

Good morning, and thank you for standing by. Welcome to the Gastar Exploration Fourth Quarter 2012 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded today, March 12, 2013.

I would now like to turn the call over to Ms. Anne Pearson of Dennard-Lascar. Please go ahead.

Anne Pearson

Thank you, Kerry, and good morning, everyone. Before I turn the call over to management, I have a couple of items to go over. First, a replay of this call will be available shortly after, by webcast, on the company's IR website, and a telephone replay will be available for 1 week. The information you need to access the replay is in yesterday afternoon's news release.

Also, today's call will contain forward-looking statements. Though management believes these statements are based on reasonable expectations, they have no assurance that they'll prove to be true. The statements are subject to certain risks, uncertainties and assumptions, as described in the company's Form 10-K and which can also be found in the Investor Relations section of the website. Should one or more of the risks materialize or should underlying assumptions prove incorrect, actual results may vary materially.

Today's call may also include a discussion of probable or possible reserves or use the terms like reserve potential, upside or other descriptions of non-proved reserves, which are more speculative than estimates of proved reserves and are, therefore, subject to greater risk. A reminder, information relayed on this call speaks only as of today, March 12, 2013, so any time-sensitive information may no longer be accurate at the time of a replay.

Now I'd like to turn the call over to Russ Porter, Gastar's President and CEO. Russ?

J. Russell Porter

Thanks, Anne, and good morning, everyone. With me this morning is Mike Gerlich, our CFO. I'll go through a review and update of our operations, and Mike will follow-up with a review of the fourth quarter financial results and a look at our guidance for the first quarter.

Our solid performance in the fourth quarter was a strong finish to an overall good year from an operations perspective. Our production volumes increased 12% sequentially and 92% compared to the fourth quarter of last year. The production increase would have been higher except for the ongoing third-party gathering system issues we've experienced in the Marcellus. We estimate that gathering system downtime reduced our current quarter production by approximately 5.5 million cubic feet a day equivalent or 13%. On a full year basis, the impact was 5 million cubic feet equivalent per day or 14%.

Even with these challenges, we've managed to significantly improve Gastar's overall performance. As proof, we reported adjusted net income of $4.4 million and adjusted cash flows from operations of $10.1 million for the fourth quarter. In addition, our proved reserves increased by 51%, and the percentage of high-value condensate oil and natural gas liquids increased to 28% of total reserves at year-end '12. This was due to our development of the Marcellus Shale in Marshall County, West Virginia. Marcellus Shale assets represent 85% of proved reserve volumes and 93% of PV-10 value for our reserves at year-end. Condensate oil and NGL reserves accounted for nearly 1/3 of total Marcellus Shale proved reserves at the year-end.

During 2012, we brought on production a total of 29 gross or 13.4 net wells in Marshall County, bringing our year-end operated Marcellus producing well count to 38 gross or 17.4 net wells. The increase in Marcellus production is helping us to achieve our objective of expanding the ratio of condensate and oil in our total production profile and increasing our cash flow. Average daily production for the Marcellus was 30 million cubic feet equivalent in the fourth quarter after being negatively impacted by continuing downstream -- excuse me, midstream downtime and high line pressure issues. Approximately 33% of fourth quarter production from our Marcellus Shale wells was a combination of condensate and NGLs. So far, in the first quarter of this year, 5 gross or 2 net additional wells have been brought on production, and we're currently at various stages of drilling and completing an additional 14 gross or 7 net horizontal operated Marcellus wells.

During 2012, we continued to focus on improving our drilling and completion processes. These efforts have allowed us to reduce drilling times by approximately 6 days compared to 2011 and thus, lower our per-well drilling completing and pad costs to a current cost of approximately $7 million. We think we can continue to lower our costs even more with further refinement of our operations. In addition, we have field tests planned for Marshall County in the first half of 2013 that could further improve our economic returns. After reviewing detailed core and reservoir analysis, we've begun drilling 4 wells on the Goudy pad, down-spaced to 400 feet apart from 600 feet, which is a typical spacing for most of our pads drilled to date. If recoverable volumes from this Goudy test compare favorably to our earlier wells, we may adopt this higher -- this tighter spacing on all future pads, which allow us to drill as many as additional 20 to 25 wells on our Marshall County acreage. We expect the Goudy production to begin by the early third quarter.

As we discussed last quarter, we're also experimenting with the orientation of our laterals on the 5-well Addison pad to test if a different well azimuth might further improve IP rates and EURs. We are currently in the process of frac-ing the 5 Addison wells and expect to pace -- place them on production by the end of this month. Once we completed the Goudy and Addison pads, we plan to suspend our operations -- or suspend our Marcellus capital program for a short period of time during the second half of '13 to monitor the production results. This suspension of drilling will hopefully allow Williams additional time to upgrade their system, get fractionation operational and add capacity. Access to fractionation should improve our NGL and condensate price realizations. Even though we are temporarily slowing down Marcellus operations, we expect to drill 9 gross wells and place on production an additional 19 gross or 9.5 net operated horizontal Marcellus Shale wells in Marshall County this year. That would give us a total of 57 gross or 26.9 net operated Marcellus wells on production by early third quarter of 2013.

The additional central receipt point or CRP at the Burch Ridge pad that was originally scheduled to come online in December is just commencing startup operations. This facility will add 70 million cubic feet per day of dehydration capacity, bringing our total dehy capacity in the field to 110 million cubic feet per day. Additional compression at Burch Ridge should be in place by April 15 to ensure line pressures are maintained at approximately 550 PSI. Once fully operational, this CRP should enable us to begin producing our Marcellus assets at more normalized rates and hopefully, with reduced downtime.

NGL yields continue to hold at approximately 45 barrels per million of natural gas produced across our acreage position, and condensate yields are currently averaging about 35 barrels per million. As a result of the high liquids [ph] production, our Marcellus drilling continues to yield very strong economic returns at today's futures pricing. Utilizing our third-party reservoir engineering firm's average 6.3 Bcfe EUR decline curve and all-in cost of $7 million for a 5,000-foot lateral, this yields an estimated 38% internal rate of return and $1.42 per MMCF equivalent finding and development costs. Overall, we have at least 114 additional Marcellus horizontal wells we drilled on our existing acreage at Marshall and Wetzel counties, and we're continuing to add acreage in locations.

Now moving to the Mid-Continent. We're continuing to build our lease position in our Mid-Continent oil play. As of the end of the fourth quarter, we had approximately 41,900 gross or 17,300 net acres. The first Mid-Continent well, which began flowback in early October, was still producing at an after-processing average growth rate of approximately 105 barrels of oil equivalent and 247 barrels of completion fluids per day as of late February. Approximately 31% of the frac fluid is flowed back as at the end of last week from that first Mid-Continent well. Flowback operations on the second well began February 15. We've modified the lateral placement and the completion methods we used on that well, and we are very pleased with the greatly improved initial flow results. Completion operations are underway on the third well in the Mid-Continent play, with initial production expected in the early second quarter. This well has a 4,300-foot horizontal lateral that is being completed using the same techniques employed on the second well. A fourth horizontal well will spud in mid-February, and we expect first production by mid-second quarter. Last year, we spent a total of $20 million in Mid-Continent, and we expect to spend about $27 million this year.

Now I'll turn it over to Mike to get to the financial results, and I'll be back with some other comments. Mike?

Michael A. Gerlich

Thanks, Russ, and good morning, everyone. I'd like to begin with just a few highlights from yesterday's news release. Then I will cover expense trends, update you on our capital budget and Q1 guidance and discuss liquidity.

Our fourth quarter revenue from natural gas, condensate and oil and NGLs production increased 93% from a year ago to $18.9 million due to a 92% year-on-year increase in production. Virtually, all of this production growth was from the Marcellus. Our current quarterly revenues continue to benefit from our hedging program. Our average fourth quarter 2012 price per Mcfe before realized hedging was $3.77 compared to $4.83 after hedging benefit, a 28% uplift in product pricing. Compared to a year ago, our average sales price per Mcfe without the impact of hedges was $3.22; and with hedging, $4.80, an increase of 49%. For sequential comparison, in the third quarter of 2012, our blended price per Mcfe before hedges was $3.28, and after the impact of hedges, it was $4.25, up 30%. The sequential price improvement, both before and after hedges, reflects the improving natural gas prices realized in the fourth quarter of 2012. Our hedge price benefits in the fourth quarter were a result of approximately 70% of our natural gas production, 39% of our condensate and oil and 64% of NGL production volumes being hedged. We continue to look for opportunities to enhance our hedging positions. Complete details about our hedged positions as of December 31 are available in our 10-K, which was filed yesterday afternoon.

Now looking at net results. On a reported basis, our net income attributable to common shareholders for the fourth quarter of 2012 was $2.9 million or $0.05 per diluted share. If you exclude the impact of unrealized hedging activity, adjusted net income was $4.4 million or $0.07 per share. That compares to an adjusted net loss of $2.3 million or $0.04 per diluted share in the fourth quarter of last year and a negligible adjusted net income in third quarter of 2012.

A brief comment about cash flow. As you saw in yesterday's press release, we were reporting a new non-GAAP cash flow metric this quarter that we're calling adjusted cash flows from operations. In the past, we reported net cash provided by operating activities before working capital changes and other special items. Adjusted cash flow from operations is that same metric, but reduced by the dividend expense we incur on the preferred shares. In accordance with U.S. GAAP, the dividend payments reported as a cash flow use within financing activities rather than as a reduction of cash flow from operations. We've decided to deduct this expense from operating cash flow, similar to interest expense. Please see yesterday's press release, which can be found on our website for a reconciliation of the most directly comparable GAAP financial measure. Using this new calculation method, current quarter adjusted cash flow from operations was $10.1 million or $0.16 per diluted share compared to $2.5 million or $0.04 per share a year ago and $7.8 million or $0.12 per share in the third quarter of 2012.

Combined average daily production of 42.5 million cubic feet equivalent came in at the midpoint of our upwardly revised guidance for the fourth quarter. Condensate oil and NGLs accounted for 24% of our production volumes compared to a guidance of 23% to 26%. The 12% increase from the sequential quarter and 92% increase versus the fourth quarter of 2011 was due to the completion of 29 gross new operated wells in the Marcellus since December 2011, including 9 new wells added in the fourth quarter of 2012. As we announced 2 weeks ago, we expect the total company production in the first quarter of 2013 to average between 41 million and 43 million cubic feet equivalent per day, assuming approximately 7 days of planned shut-in for maintenance of the third-party gathering system and commencement of the Burch Ridge CRP by mid-February. Though the planned shut-in for maintenance went as scheduled, we must further curtail our production during the first quarter due to hydrate issues, coupled with delays in startup of the new CRP. As a result, our revised production guidance for the first quarter is 38 million to 41 million cubic feet equivalent per day, at which condensate oil and NGLs will account for 25% to 27%. The higher liquids percentage is due to new Marcellus wells coming online, initial contributions from the first Mid-Continent wells and natural declines in East Texas dry gas production. We expect liquids will continue to trend upward as a percentage of total production throughout this year.

Now I'm going to discuss some of our key expense items during the fourth quarter and review the related Q1 guidance we provided a couple of weeks ago. Our lease operating expense totaled $1.4 million versus our guidance of $1.7 million to $2 million. Our LOE in the prior year period was $2.7 million. The variance to our guidance was primarily due to lower workover cost and lifting cost in East Texas. On an Mcfe basis, LOE was $0.36 compared to $1.32 a year ago. For the first quarter, we expect total LOE to be on the low side of our range of $1.9 million to $2.1 million. Production taxes for the fourth quarter were $775,000, up from $236,000 a year ago. As you will recall, our Marcellus production is not exempt from production taxes, while our East Texas production has been and continues to be exempt under the Texas tight sands credit. The DD&A rate in the fourth quarter was $1.45 per Mcfe, down $0.59 from the prior quarter. The sequential decline was largely due to the 2012 ceiling impairments recorded in the second and third quarters, coupled with higher year-end reserves.

Transportation, treating and gathering expense of $1.3 million for Q4 were in line with previous quarterly guidance of $1.2 million to $1.4 million. For the first quarter, we expect it to again be in the similar range of $1.2 million to $1.4 million. Cash general and administrative expense for the fourth quarter was $2.2 million, about the same as a year ago and at the low end of our guidance range of $2.2 million to $2.4 million. Noncash stock compensation expense was $720,000, which was about flat versus the prior quarter. For the first quarter, we expect cash G&A of about $2.5 million to $2.7 million, with a bias to the low end of that range, coupled with noncash stock compensation expense of about $1.1 million to $1.3 million.

Moving to the balance sheet. At December 31, we had cash and cash equivalents of $8.9 million and long-term debt outstanding of $98 million. We are allowed one additional borrowing base redetermination annually, and in December, we requested such, based on the December 1, 2012, reserve report. As a result, the borrowing base on our revolving credit facility was increased from $110 million to $125 million, effective December 31. As of today, we have $100 million of debt outstanding under our revolver, an increase of only $2 million from the year-end balance, resulting in $25 million of current availability. The current cash balance is approximately $4 million. The next regularly scheduled redetermination is set for May 1, 2013. We expect to see another borrowing base increase based on our year-end reserve report, as we continue to bring additional proved, developed, producing wells online in the Marcellus.

We had a net working capital deficit at the end of the fourth quarter of $30.2 million. This includes advances from nonoperating partners totaling about $17.5 million. At December 31, we were not in compliance with our working capital ratio covenant for our revolving credit facility, but we were granted a waiver for the covenant violation from our lenders, and we amended the working capital covenant calculation for 2013. Total preferred shares issued and outstanding was unchanged from last quarter. We currently have 3,951,254 preferred shares outstanding, with a total liquidation preference of approximately $98.8 million. We approximately have 95,000 preferred shares authorized but unissued.

Looking at CapEx. We spent a total of $41 million in fourth quarter, bringing our full year CapEx to $146.4 million, which is in the middle of our revised 2012 budget of $135 million to $152 million. Our current 2013 CapEx budget is $93 million, which is materially lower than 2012 but still supports a program that will continue delivering volume and reserve growth. Of the $93 million, $75 million is for drilling, completion and infrastructure; $15 million is for leasing and seismic; and $3 million is for other capitalized costs. Geographically, $60 million is allocated to the Marcellus, $27 million for the Mid-Continent and $2 million for East Texas. In total, 99% of drilling and completion capital dollars will target liquid-rich wells this year and 81% of total planned capital spending will be dedicated to drilling.

Now I'll turn it back over to Russ for final comments. Russ?

J. Russell Porter

Thank you, Mike. I just want to wrap up our prepared remarks by saying, again, that we're extremely pleased with the results of the Marcellus activities. We've experienced some challenges in 2012 in the form of continued pipeline constraints on our Marshall County production and lower commodity prices, not just for natural gas but also for condensate and NGLs. We hope that bringing a new Burch Ridge CRP online will result on the majority of the Williams issues being behind us. Despite lower natural gas liquids prices, the internal rate of return on our Marcellus wells is very attractive. We're optimistic that downspacing and other refinements in our development plan for Marcellus will further enhance the return on those assets.

Just as important, I want to repeat that we're very encouraged by the early results of the second Mid-Continent well. We've seen oil production from the first day of flowback and are currently producing at rates that easily exceed our unrisked IP projections of 400 barrels of oil per day. We continue to believe that the Mid-Continent play will provide another operating area where, like the Marcellus, we can drill wells that generate attractive returns in a low-risk and low-cost environment. We'll provide additional detail on the Mid-Continent play as soon as we can do so without interfering with our long-term plans for the play.

That concludes our prepared remarks, and now we'll turn it over to questions and answers.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question today comes from Ron Mills with Johnson Rice.

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

Russ, a couple of questions, one on the Mid-Continent. You talked about targeting a different portion of the formation. Can you add a little bit more color as to why you decided to target the second -- or lower part of the formation and some of the different attributes to it -- of that?

J. Russell Porter

Sure, Ron. We decided to target the lower portion of that formation because we thought that there was an additional unconformity that might result in more natural fracturing. That is, in fact, what we found. We also found that just above that portion of the formation where we have drilled the second, third and we're now drilling the fourth lateral, there's a pretty gas-rich shale zone just above that, that appears to be a bit of a pressure barrier, which we think is allowed that portion of the formation to retain more gas and thus, give us more energy in the reservoir, if you will. So we basically went there looking for more fracturing and found more fracturing and some additional gas, which helps in the drive of the reservoir.

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

Okay. And I think you walked through the year-end acreage positions. You've added another kind of 2,000 or 3,000 acres since year-end. Where do you stand in terms of -- are you still doing bits and pieces on the ground? Are there bigger pieces that you may be targeting in terms of what your eventual goal of acreage may be in that play?

J. Russell Porter

We haven't really got a hard goal. We're trying to keep pick up as much as we can at the attractive prices we're able to lease at now. We're continuing to pick up, fill in the gaps within our existing position. There are a few more sizable tracks out there or packages that we're pursuing, and that's the part of the reason why we're continuing to be fairly quiet on details as far as location and formation, et cetera.

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

Okay. And then, Mike, you walked through your first quarter guidance. On your third quarter call, I think you had talked about a rough number of 10% to 30% type growth for 2013 based on that budget. Is that something that's still in line? Or how should we think about 2013, given what looks to be a pretty significant ramp in the second and third quarters versus the first?

Michael A. Gerlich

Yes. As we've talked about we're delaying our capital in the Marcellus. We'll continue our activity in the Mid-Continent. But the real driver to our production growth has been the Marcellus. But even though we're delaying it, we still plan to have 57 gross Marcellus wells on by the end of June. And so really, our second and third quarter growth should be fairly significant kind of plateau and hold through the fourth. So yes, that 10% to 30% growth is still very much achievable even with the delayed and reduced capital program.

Operator

And our next question comes from Mr. Chad Mabry at KLR Group.

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

I had a question for you on acreage exploration. Looking to the 10-K, it looks like you have about 19,000 gross, about 9,000 net acres in the Marcellus West that are set to expire this year. Do you expect that most of this position will be captured by your planned drilling activity this year?

J. Russell Porter

Yes.

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

Okay. Sores in your eye for asking for a close-ended question. I guess I can go over to the Mid-Continent. Just curious then how much acreage you're going to have earned following the first 4-well prospect area there.

J. Russell Porter

We're earning the acreage that are drilled in each one of those units, but we've got an assignment of our net position across all the acreage that's been bought today.

Operator

And our next question comes from Neal Dingmann at SunTrust.

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

Say, Russ, can you talk a little bit about -- on the press release, you mentioned that testing for the different drilling orientation to improve the reserves. What -- maybe give a little more color on what the plans are around that sort of near term or how you see that developing?

J. Russell Porter

Okay. On the Addison pad, we've drilled those wells on a slightly different azimuth than the previous wells we've drilled in the field. So the reason for that was the microseismic data that we have collected across the area show that we were not exactly perpendicular to the major stress in the field. Despite that, we've been getting very good completions and seeing very complex fractures that are being created with our completions. Stone down to the south of us has drilled on a different azimuth that we're testing with the Addison wells, and it looks like their results have also been very good. So it's -- simply is an opportunity because of the configuration of those leases, that allowed us to drill our targeted length laterals on that different azimuth. We've started frac-ing those. They're frac-ing a little bit differently than the previous wells. We'll know a lot more when we put those on production. But if it works, we'll re-permit and change the azimuth on future wells, so it really won't affect our well count very much at all. If it doesn't work, if those wells aren't as productive as our past wells, then we simply go back to the original azimuth and continue on with that program. But it's just one of several things we're trying to optimize our recoveries from the oil position.

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

Got it. Got it, okay. And then, just on -- you put on the press release just about the delay on the CRP. I guess, going forward, as you continue to expand, you obviously have a great improvement on your well results in the Marcellus. What have you seen as far as just development of infrastructure, I guess, going forward? Give us some confidence on, you'll continue to have ample takeaway. And then, I guess just sort of second question, I'm assuming over in the Mid-Continent, there's no takeaway issues going forward.

J. Russell Porter

In the Mid-Continent, no takeaway issues whatsoever. Your question is a good one, Neal, because we're pretty frustrated with third-party, i.e., Williams, issues that we've continued to experience. We've drilled -- we put a lot of capital in place. We've drilled the wells. The wells are very productive, and it's pretty frustrating that we're held back by issues that are a bit out of our control. Going forward, we have the right to construct future CRPs which puts that timing in our hands and not in someone else's. We still -- we'll need Williams to perform, as far as the processing assets that they have in place, fractionation and the other assets that they're required to have in place contractually. We hope that they're true to their word and they're working through these problems and that they'll be resolved. The problems get -- they get easier for us to handle as our production volumes get higher and higher because they have less and less of an overall impact. But it's been a very frustrating experience for us to perform so well on our side of the equation and be held back by issues that are really not in our control.

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

Russ, does it appear that anybody else would be coming up in that area to give them a little competition?

J. Russell Porter

You've got MarkWest over further to the east, but they don't have any pipe into our area. You've got Dominion over in that area, but they don't appear to be on any faster track than anyone else from what we've seen. And we've dedicated our acreage to Williams, and unless they'll don't perform, to the point of us, decided that they're in breach of the contracts and trying to get out of that dedication, we're pretty well -- we're married to them, and we've got to figure out a way to work out the marriage.

Operator

And our next question comes from Hoshang Daroga at MLV & Co.

Hoshang V. Daroga - MLV & Co LLC, Research Division

A quick question on the Eaglebine, have you guys de-risked the Eaglebine a little more so that you guys are comfortable selling these assets to -- are you looking at monetizing this or JV-ing it?

J. Russell Porter

I can't say we've really de-risked it more. We haven't put any capital into the play. As we've said for several quarters now, we're monitoring what other operators around us are doing, primarily EOG and EnCana. But as we mentioned, the divestiture of those assets is a possibility. And while we look at it with both the Marcellus and the Mid-Continent generating very high returns, even if the Eaglebine looks attractive, I'm not sure it's attractive enough to ever take capital away from those other 2 plays. So we're in a position where we've got a finite amount of capital. We're going to chase the highest returns available for our shareholders. So at some point, it probably makes sense to divest that asset and redeploy the funds in areas where we can generate a higher return.

Hoshang V. Daroga - MLV & Co LLC, Research Division

Are you guys in talks of divesting this asset? Or is it just in the board room?

J. Russell Porter

We've begun the process.

Hoshang V. Daroga - MLV & Co LLC, Research Division

Okay, fair enough. And we saw a good decline in the DD&A rate in 2012 in the fourth quarter, I mean per barrel, per BOE, should we expect that to stay flat in 2013 going forward or any particular guidance?

Michael A. Gerlich

That's always difficult to predict because so much is dependent upon, one, where our product price is, since you use the SEC reserves; and two, what's the booking of the offset PUD activity. And if you remember our press release back in February, we stated that, basically, we have the equivalent of one PUD location for every proved developed location we had in the Marcellus. Yes, I don't see us going up necessarily to that $1.92 we had talked previously guidance-wise. But this $1.45 to $1.60-ish range is probably, at this point, as good of an estimate as we can give.

Hoshang V. Daroga - MLV & Co LLC, Research Division

Okay. And one last question, any particular milestones that you're looking for in 2013?

J. Russell Porter

Milestones in 2013? I mean, a milestone, for us, would be getting these midstream issues worked out and being able to demonstrate the true productive capacity of our Marcellus wells. We will provide additional details on the results and the plans for the Mid-Continent as soon as it makes sense for us long term to do so. And then, just continued execution. We're very pleased with execution we've seen in the Marcellus, where most of our capital is going. And if our team up there continues to perform the way they have for the past 18 to 24 months, we'll be in very good shape.

Operator

And our next question comes from David Deckelbaum at KeyBanc.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

I just had a quick question on the East Texas asset sale. One, could you give us any color just on how the process is going to work and potential timing around there, as the formal data room open? And two, have you discussed with your lenders yet how a potential sale might impact your credit facility?

Michael A. Gerlich

We have discussed with our lenders how a potential sale would impact the credit facility, and we have a good understanding of that. And certainly, we wouldn't be undertaking this if we didn't think it created additional liquidity net of that impact. We have had a data room open. We've had multiple parties come through and shouldn't -- and we're in discussions with multiple parties.

Operator

[Operator Instructions] It looks like we have a follow-up question from Nicholas Snyder at Union Square.

Nicholas Snyder

Looking at the terms of the waiver you received on the revolver, it looks like you now have the ability to issue another 20 million or so of the preferred. Is that something we should expect in 2013? Or is this more a question of flexibility?

Michael A. Gerlich

It was more of addressing flexibility just, again, to give us, should the market and the opportunity present itself, the ability to do that and move quickly because those markets are pretty dynamic sometimes. But at the current level of our preferred, we're not really looking at that at this time.

J. Russell Porter

So to be very clear, we don't have any plans to issue additional preferred.

Nicholas Snyder

Okay, that's helpful. Also, can you give us an update on the Chesapeake lawsuit just in terms of timeline? What's the next sort of event or milestone we should be looking to?

Michael A. Gerlich

We're still waiting on the federal court to rule on the arbitration issue, and there's really been no change in that. We don't know when to expect it exactly, but one would think it would be probably not-too-far-distant future. Other than that, there's been no changes whatsoever and really, nothing we have to add on the litigation beyond what we've said in the past.

Nicholas Snyder

Okay. And just a follow-up on the Mid-Con. It sounds like the second well you're getting some also encouraging results, which is nice to hear. Is there a reason that there's very long period of flowback of the frac-ing fluids or something like that, that's causing you to not be able to release results in a more timely fashion from these wells?

J. Russell Porter

Well, we're not releasing results due to the fact we don't want to put ourselves in a competitive disadvantage so that has nothing to do with well performance whatsoever. As I mentioned in my comments, we saw oil flow from the very first day of flowback on the second well. That well is flowing at very encouraging rates, with less than 5% of the frac fluid recovered. So there's nothing about the performance of the wells that's impacting our decision to hold off on addition -- not releasing any additional information.

Nicholas Snyder

Okay. And can you give us any idea of when we should expect to hear about that? I mean, obviously, it's -- this play is going to be, by the end of this year, close to $50 million, which is more than 1/2 of your market cap. So obviously, as an investor, we're anxious to hear more about what's going on there. Is that going to be first half of this year that we would have more of a view into that?

J. Russell Porter

We're going to issue additional information when it's in everyone's best interest, primarily our shareholders, to do so. We're -- we think we've got a very attractive situation. We're trying to maximize it at as well a cost as possible, and that's difficult to do if you let too much information out, given the competitive nature of this industry. So we'll drink no wine before it's time and we'll make no announcement before it's time.

Operator

At this time, I'll turn it back to management.

J. Russell Porter

All right. Thank you, everyone, for joining us this morning. As always, if you have additional questions, you can feel free to contact myself or Mike at our office, and we thank you for your continued interest in Gastar.

Operator

Thank you for joining the Gastar Exploration Fourth Quarter 2012 Earnings Conference Call. If you wish to listen to a playback of this conference, please dial 1 (866) 949-7821. You may now disconnect.

Anne Pearson

Thank you, Kerry.

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