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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

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

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

Patrick B. Rigamer - Iberia Capital Partners, Research Division

Gastar Exploration (GST) Q1 2013 Earnings Call May 3, 2013 10:00 AM ET

Operator

Good morning, and thank you for standing by. Welcome to Gastar Exploration's First Quarter Earnings Call. [Operator Instructions] As a reminder, this conference is being recorded today, May 3, 2013. I would now like to turn the call over to Lisa Elliott, with Dennard-Lascar Associates. Please go ahead.

Lisa Elliott

Thank you, and good morning, everyone. We're pleased to have you joining us on this conference call to discuss Gastar's first quarter results for 2013.

And today's call will contain forward-looking statements. Although management believes 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 subsequent Form 10-Qs, which can also be found in the Investor Relations section of the website. Should one or more of these risks materialize or should underlying assumptions be proven incorrect, actual results may vary materially.

And today's call may also include a discussion of probable or possible reserves or 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.

A replay of today's call will be available and accessible via webcast by going to the IR section of Gastar's website and also by telephone replay. You can find the replay information both in yesterday's news release. And as a reminder, information reported on this call speaks only as of today, May 3, 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, Chief Executive Officer. Russ?

J. Russell Porter

Thanks, Lisa, and good morning, everyone. Mike Gerlich, our CFO, is with me, and he'll have comments following my initial comments.

I like to begin with brief comments on the 2 significant transactions we announced in the month of April and which we expect to close in early June. Then I'll go through a review and update of our operations, Mike will follow up with a review of first quarter financials, our guidance for the second quarter, our liquidity position and a few other items.

I'll begin with our announcement on April 22 regarding our agreement to sell our East Texas assets to Cubic Energy for $46 million. We expect the transaction to close on or before June 5, with the property sale effective date of January 1, 2013.

The Hilltop area of East Texas and Robertson and Leon counties have been the primary focus of the company since we participated in our first deep Bossier well in 2001. We drilled a total of 36 wells, and we're proud of the success we achieved at defining the geologic opportunity, developing the right drilling and completion techniques and safely operating for over a decade.

Despite drillings from outstanding wells on that acreage, the economics of the dry gas deep Bossier wells are not as compelling as our other investment opportunities based on our current and projected future natural gas prices. Monetizing these Texas assets and redeploying the capital is the next natural step at our evolution to explore for and develop higher-value oil, condensate and natural gas liquids.

We have 2 exciting projects we are currently focusing on. Our highly successful ultra-rich gas Marcellus Shale project in West Virginia and our emerging Hunton Limestone oil play in North Central Oklahoma. Our Oklahoma project was formerly referred to as our Mid-Continent project where through a joint venture, we began leasing acreage in January 2012. We're encouraged by the initial success of that program, and we're expanding our exposure to the play through our other pending transaction, the acquisition of 157,000 net acres adjacent to and near our current leasehold. I hope that you were able to join us on the conference call last month when we discussed the Oklahoma acquisition in detail.

We announced a transaction with Chesapeake Energy on April 1, and it is expected to close on or before June 7. The acreage to be acquired offers a large inventory of what we believe will be repeatable crude oil-rich drilling prospects that should keep us actively drilling there for many years. When the transaction closes, we'll have approximately 275 net potential drilling locations in the Hunton Limestone oil play that expose us to more than 100 million barrels of oil equivalent of net resource potential. This includes 65 locations on our original AMI and more than 200 net locations that we feel are most prospective for Hunton development on the acreage we're acquiring from Chesapeake. We're acquiring the drilling rights from the top of the Mississippi Lime and deeper.

The package also includes 176 producing wells, with current daily net production of 177 barrels of crude oil, 54 barrels of natural gas liquids and 3.5 million cubic feet of natural gas per day, with approximately 2.6 million barrels of oil equivalent of proved, developed, producing reserves. These wells are currently generating cash flow of about $500,000 to $600,000 a month, so this cash flow will more than offset the monthly cash flow that we're losing in the East Texas sale.

Also, as a part of that transaction, our 2 companies have agreed to settle all pending litigation regarding our East Texas properties, and Chesapeake agreed to sell Gastar, the GST common shares they own just under 10% of us, at $1.44 a share. It's been very nice to see our common stock price react favorably to these series of recent developments.

Gastar is undergoing a lot of change over the past 4 years, driven mainly by the shift in economics in the natural gas business. We are successfully steering to that change by transitioning our portfolio of assets to capture the best opportunities for strong returns on our investments and the best opportunities to build value for our shareholders.

We try to be agile, and we build value by getting into these plays early at a low cost and by adopting best practices for drilling and completions in each area in which we operate. That's the model we plan to continue to follow.

Now turning to the results of operations in the first quarter and starting with the Marcellus. During Q1, we brought on production 10 gross or 5 net operated Marcellus Shale wells in Marshall County, West Virginia from the Shields and Addison pads. That brings a total number of wells on production to 48 gross or 22.4 net as of March 31.

We are currently drilling or completing 9 gross for 4.5 net wells on the Shields and Goudy pads that we expect to put on production in the second quarter or very early in the third quarter.

Net production from the Marcellus averaged 28.5 million cubic feet equivalent per day, which was double our production rate from this area in the first quarter of last year, but it was 1.5 million below our production rate in the prior quarter. That sequential decline was due entirely to issues we were having with the third-party-operated gathering system and midstream infrastructure that serves our field.

You'll recall from last quarter that we expected a significant but temporary curtailment in Marcellus production, while Williams conducted a planned weeklong shut-in for maintenance work. In addition, Williams also experienced a rupture on their 24-inch pipeline on March 22. Initially, we didn't anticipate significant impact on our production since our gas is transported through a different 15-inch pipeline.

However, in order to avoid shutting in some of their other customers who were impacted by the severed 24-inch line, Williams diverted gas onto the 15-inch line that serves our wells. That's increased the already high line pressures on the smaller pipeline even more. Plus, the startup of the second CRP in our Burch Ridge pad was delayed. Despite these continuing midstream issues, we were able to meet our revised production guidance for the quarter.

We estimate that the impact -- or the combined impact of Williams pipeline and related facilities problems reduced our current quarter net production by an average of 16.8 million cubic feet a day equivalent or 42% of our total reported production for the quarter. Based on realized monthly product pricing, that comes out to about $6.7 million of net revenue after production taxes and an equal amount of bottom line cash flow. By comparison, a year ago in the first quarter, we estimated that pipeline constraint issues on the gathering system only cost us about 4.9 million cubic feet equivalent per day or 17% of our then total company production and net revenue of $1.8 million.

The good news is that the new Burch Ridge CRP is finally in service as of late March, bringing total dehy capacity for our natural gas production up to 140 million cubic feet per day. Williams also added compression at Burch Ridge in mid-April, so April volumes have been a lot better, and early May gross volumes are even higher.

For the first quarter of 2013, our daily gross gas volume was 47 million cubic feet a day compared to an April average of 69 million cubic feet per day, with an exit rate at the end of April of 82 million cubic feet per day. These higher gross gas volumes will mean corresponding increases in our condensate and NGL volumes from these wells.

Our first quarter condensate and NGL yields in the Marcellus were negatively impacted by the gathering system high line pressures. During the current quarter, our condensate NGL yields per million cubic feet of gas were only 29 barrels and 30 barrels, respectively. The new CRP and related compression should allow Marcellus gas production yields per million cubic feet to return to the more normal range of 35 to 45 barrels of condensate and 45 to 50 barrels of NGLs for the second quarter and the remainder of the year.

Following the completion of the 9 wells we now have underway, we plan to take a break from new drilling, which will enable us to allow -- which will enable us to observe and evaluate the results of tighter well spacing on the Goudy pad and different lateral azimuths we have utilized on the Addison pad to see if they generate better production rates or better EURs, both of which could improve the economics on the play.

This break in drilling activity will also allow Williams additional time to continue to upgrade their system, hopefully start up their fractionation facilities and improve system run times. Access to new fractionation capacity should improve the price realizations for our NGLs and condensate.

Despite the pause in drilling in the Marcellus, we still expect to place on production a total of 19 gross or 9.5 net operated horizontal Marcellus Shale wells in Marshall County this year. We expect to have all currently planned 2013 Marcellus wells on production by the end of the second quarter or in the first week of the quarter -- of the third quarter. At that time, we'll have 57 gross or 26.9 net producing Marshall County wells.

The average gross total drill and complete cost for our last 23 Marcellus horizontal wells, which have had an average lateral of 4,660 feet, was $6.7 million, including pad or location cost. We continue to be very pleased with the results of our Marcellus activity, and we continue to look for opportunities to expand and optimize our acreage position. We expected to spend a total of about $60 million in CapEx in the Marcellus this year.

Now moving to the Hunton Limestone oil play in Oklahoma. We have drilled 4 wells so far in our original AMI that -- AMI area that includes acreage in Major, Kingfisher and Garfield Counties. Our second Hunton well has performed exceptionally since flowback operations began in mid-February.

The #2 well produced at an average gross rate of 1,169 BOE per day, 85% crude oil, for the 30 days ended April 30. Our original expectation for this well based on a type curve was a peak production rate of 645 BOE per day. That well is producing at nearly twice that rate over the last month.

Our first Hunton well, which was drilled at a different portion of the formation and completed with fewer frac stages, produced at an average gross rate of 58 BOE per day over the same period, which was down from the prior quarter. That well began producing in early October 2012.

Flowback operations on the third well began on April 4, and it is now producing oil and completion fluids at a total rate of approximately 1,000 barrels per day with a 5% to 8% oil cut. Initial oil production from this well has been delayed as a result to problems with the gas lift compressor. The compressor was shutting down daily, and so with each startup, we were essentially beginning the completion fluid recovery process all over again. The compressor was replaced last Friday and, as well, is starting to produce oil and natural gas. As of today, only about 12% of the completion fluids have been recovered. We're encouraged by the high total volume fluid -- the high total fluid volumes, and consistent with our other wells in the play, we expect the wells to produce an increase in oil cuts as additional completion fluids are recovered.

Completion operations were recently finalized on the fourth horizontal well and the original AMI. Flowback operations are just now commencing. As previously reported, we will now take a brief drilling break and evaluate the production results of these wells and focus on the completion of the Chesapeake property acquisition. We expect to resume drilling sometime in the third quarter on the original AMI we plan to drill -- where we plan to drill and complete 4 more non-operated wells this year.

On the new acreage we're acquiring from Chesapeake, we expect to drill 4 operated wells in 2013, with the first one also spudding sometime in the third quarter.

The last 7 Hunton horizontal wells drilled by our operating partner outside of our existing AMI are the basis for our type curve, and they've averaged -- they've realized an average gross production rate or peak gross production rate of 645 BOE per day, with internal estimated gross reserves of 436,000 BOE per well. The gross drill and complete costs per well are approximately $5.2 million.

Including the cost of the 4 wells in a new area, but excluding the cost of the Chesapeake acquisition, our total 2013 CapEx budget for the Oklahoma area grows to $37 million.

Now I'll turn it over to Mike to go to the financial details. I'll be back with a few other comments.

Michael A. Gerlich

Thanks, Russ, and good morning, everyone. I'd like to begin with the highlights from yesterday's news release, then I'll cover expense trends, our overall liquidity position and provide Q2 guidance.

Looking first at the top line. First quarter revenue from natural gas condensate and oil and NGLs production increased 96% from a year ago to $20.9 million. This was in part the result of a 36% year-over-year increase in production, almost all of which was from growth in the Marcellus Shale, which offset natural gas production declines in East Texas.

First quarter revenue benefited from the growing volume of higher-value oil and condensate and NGLs in our overall production mix, which represent approximately 46% of our total revenues before unrealized hedge impacts for the first quarter compared to 40% for the fourth quarter and 35% for the first quarter of '12.

First quarter revenues were also positively impacted by a 44% increase in our average realized commodity price, which reflects the benefit of higher product prices and realized hedging gains.

Our average first quarter 2013 price per Mcfe before realized hedging was $4.19 compared to $5.73 after the hedging benefit, which represents a 37% gain in product pricing due to hedging. In the first quarter, approximately 73% of our natural gas production, 36% of our condensate and oil and 70% of our NGL production volumes were hedged.

We continue to look for opportunities to enhance our hedge positions. You'll find complete details about our hedge program as of March 31 in our 10-Q, which was filed yesterday afternoon.

Turning now to our bottom line results. On an adjusted basis, net income attributable to common shareholders for the first quarter of 2013 was $6.1 million or $0.09 per diluted share as compared to an adjusted net loss of $3.5 million or $0.06 per share a year earlier. This adjusted number is the latest -- in the latest quarter primarily excludes the impact of 2 items: an unrealized hedging loss of $9.7 million and litigation expense of $1 million related to the settlement with Chesapeake. On a reported basis, we had a net loss of $4.6 million or $0.07 a share compared with a reported net loss of $6.3 million or $0.10 a share in the first quarter of 2012.

Looking at adjusted cash flow from operations, which we now define as net cash from operations before working capital changes and other special items minus dividends paid on our preferred shares. Q1 adjusted cash flow from operations was $13.1 million or $0.21 per diluted share compared to $2.9 million or $0.05 per share a year ago and $10.1 million or $0.16 per diluted share in the fourth quarter of 2012.

Looking at our production. Combined average daily production was 40.5 million cubic feet equivalent, which was near the upper end of our revised Q1 guidance of 38 million to 41 million cubic feet equivalent per day. That's a 36% increase year-over-year but down about 7% on total production as predicted from the fourth quarter.

Condensate, oil and NGLs represented almost 26% of our production volumes, which is in the middle of our guidance of 25% to 27% versus 24% liquids in the fourth quarter. This year-over-year increase was due to the 38 gross operated wells that were on production in the Marcellus as we exited 2012 and the addition of 10 new operated Marcellus wells in the first quarter of 2013, along with contribution from our first 2 Hunton Limestone wells. Our Marcellus production averaged 28.5 million cubic feet equivalent per day in Q1 compared to 30 million cubic feet a day in Q4. The small sequential decline in production was a result of the gathering system issues that Russ described earlier.

The first quarter production in Texas was 11 million cubic feet equivalent per day. Oklahoma production in the first quarter average was just under 1 million equivalent feet per day, of which 83% was oil.

If we assume that our Marcellus curtailment is no more than 10% during the second quarter, our total company production guidance for the second quarter is 52 million to 55 million cubic feet equivalent. That guidance assumes that we had about 4.9 million cubic feet equivalent per day of production from the Chesapeake acquisition beginning June 7, which is a closing deadline of the transaction, of which 28% is liquids, and if we drop about 11 million cubic feet per day of production from our East Texas dry gas acreage beginning June 5, which is a closing deadline for the sale of our Texas properties.

As a result of continued growth in rich gas production in Marcellus, the addition of oil barrels [ph] from Chesapeake acquisition and the elimination of our Texas gas production for a portion of third quarter, we expect condensate, oil and NGLs to increase to 30% to 34% of total production in the second quarter. Post-Texas sale and assuming the benefit from our Chesapeake acquisition, our near-term future liquids percentage should be more in the range of 35% to 38%.

Looking next at some of the key expense items in the first quarter. Our lease operating expense totaled $1.8 million, which was below our guidance range of $1.9 million to $2.1 million and well below expense of $2.4 million in the first quarter a year ago. The variance to our guidance was primarily due to lower general LOE cost.

On a per Mcfe basis, lease operating expense was $0.50 versus $0.90 a year ago. The decrease in per unit cost was due to higher production volumes, the sale of our Wyoming assets last year and lower East Texas cost.

For the second quarter, we expect total LOE to be in the range of $2 million to $2.4 million. The sale of East Texas and the purchase of the Oklahoma properties will have a minimal impact on total quarterly LOE from current levels, as both properties' LOE are about equal in total.

Production taxes for the first quarter were $643,000 versus $453,000 a year ago. A reminder that our Marcellus production is not exempt from production taxes, while East Texas production is exempt under the Texas tight sands credit. Just as our revenues grow in West Virginia and Oklahoma, our production taxes will be increasing based on those states' tax rates.

The first quarter DD&A rate per Mcfe was $1.47 versus $2.11 per Mcfe a year earlier. The year-over-year decline was due to lower accrued cost resulting from ceiling impairments we booked in the second and third quarters last year combined with higher proved reserves. Compared to the fourth quarter of 2012, the Q1 DD&A rate was up $0.02 per Mcfe.

Transportation, treating and gathering expense was $1.2 million, in line with our guidance of $1.2 million to $1.4 million. East Texas represented 80% or $927,000 of the total. When East Texas sale closes, our future transportation, treating and gathering expense will decline. Assuming the sale of East Texas in early June, our guidance for Q2 transportation, treating and gathering cost is $800,000 to $1 million. Post-Texas sale, this expense should be more in the range of $300,000 to $400,000 per quarter.

Cash G&A expense was $2.2 million, which was flat with the prior quarter and below our guidance of $2.5 million to $2.7 million. The favorable variance is due to our higher allocations of capitalizable personnel cost related to bonus payments.

Noncash stock compensation expense was $823,000, which is up about $100,000 from prior quarter but, again, below our forecast of $1.1 million to $1.3 million. The lower number is due to reduced impact of annual employee stock awards granted in January 2013.

For the second quarter, we expect cash G&A of about $2.2 million to $2.5 million and noncash stock compensation expense of about $800,000 to $1 million. You should note that cash G&A guidance does not include any onetime due diligence costs we incurred as a result of the acquisition of the Oklahoma properties.

Moving to the balance sheet. As of March 31, we had cash and cash equivalents of $7.1 million and long-term debt outstanding of $115 million. On March 31, the volume based on our revolving credit facility was increased from $125 million to $160 million. We continue to have $115 million outstanding on that facility, leaving $45 million of borrowing currently available. We have a net working capital deficit of approximately $51.4 million. That includes $33.6 million of advances from nonoperating partners. Total preferred shares issued and outstanding were unchanged from year-end.

CapEx invested in the first quarter was $35.2 million. We announced as part of the Hunton Limestone acquisition that we planned to increase our 2013 CapEx budget by about $11 million to fund drilling on the new Oklahoma acreage, which would put total 2013 capital expenditures at about $102 million. We plan to solicit a joint venture partner for a new Hunton Limestone leasehold. So depending on our success in those negotiations, terms and timing, our 2012 capital expenditure number could change some.

Of the $102 million, which excludes the purchase price of the new Oklahoma assets, $83 million is for drilling, completion and infrastructure, $15 million is for leasing and seismic, and $4 million is for other capitalized cost. Geographically, $61 million is allocated to the Marcellus and $37 million for the Hunton Limestone.

We plan to fund our 2013 capital budget and pending acquisition through cash balances, internally generated cash flow from operations, proceeds from the pending sale of East Texas, borrowings under our revolver, the issuance of debt or preferred equity securities and proceeds from a possible joint venture of our new Oklahoma properties.

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

J. Russell Porter

All right. Thanks, Mike. I'd like to underscore what an exciting time this is for our company. Our Marcellus project is performing well beyond our initial expectations. The gas have continued to get richer as we continue to work our way west on our acreage in Marshall County, West Virginia.

NGL prices have continued to be weak, but the rebound that began late last year in natural gas prices has been a very welcome trend and certainly adds to the economics of our Marcellus assets.

We're optimistic that bringing the new Burch Ridge CRP online, along with the other improvements that Williams is making, will enable us to produce our Marcellus wells at more normalized rates during the second quarter.

We estimate that, absent any of the high line pressure issues or other issues with the midstream assets, our current wells are capable of gross natural gas production rates of 110 million cubic feet per day as compared to the gross rate of 47 million a day we averaged in Q1.

The significant expansion of our leasehold in the Hunton Limestone oil play has the potential to be a game changer for our company, in the same way our entry into the Marcellus transformed our company and positioned us to provide strong value creation for our shareholders.

Our early results are exceeding our expectations by a wide margin, and we look forward to testing more of our acreage with the drill bit in the second half of this year.

That concludes our prepared remarks. At this time, we'll take questions and answers.

Question-and-Answer Session

Operator

[Operator Instructions] We'll begin by taking our first question from Mr. Ron Mills at Johnson Rice.

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

A question on -- I guess a 2-part question on the Hunton. As you look -- as you go into the early flowback portion of this third well and now that you have the issues resolved, if you compare where we are in terms of fluid recovery and oil cut in this well versus the second well, how is this tracking? Or what are your expectations for how the flowback process occurs first? And then secondly, you mentioned, Mike, the Hunton JV opportunities. Is that something new that is already underway? Or what's the potential timing of that?

J. Russell Porter

Okay. The first question, it's a little bit difficult to answer because on the third well, every time that compressor was going down, we essentially had to start all over with the fluid recovery process. So with actual, we're at 11% or 12% recovery now and seeing -- the oil cuts we're seeing, really, you can't compare with the first well or the second well with its recovery. The way I look at it right now, we're 1% or 2% recovered from our -- from the -- this kind of the steady run of the compressor, and we were seeing oil and gas. And there's nothing to indicate this well shouldn't be capable of getting up to our type curve. The second well was, I think, a bit of an anomaly. It made 250 barrels of oil the first day. And yes, it's just been a monster since then. So hopefully, we'll have some more of those. But if all these wells just perform on our type curve, Gastar is in really good shape. As far as the JV, we have already started that process. We've had a potential JV partner who's -- we have potential JV partner who's currently evaluating it. We've also -- are starting the wheels turning on a process to go out to a much wider audience if our early contacts don't result in a transaction that we think is best for the company.

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

Okay, great. And then as it relates to the Marcellus and when you take unit -- take a pause and evaluate the results up there, you're also going to take a pause in the Mid-Continent. The second quarter is strong. As we look out to the third quarter, though, including the impact of the sales and the timing of completions, how should we think about just the production profile, with the understanding that the higher-value oil/liquids component will offset a volume impact?

Michael A. Gerlich

Ron, as far as the third quarter, I don't see it changing that much from what we've guided you from the second quarter. We're bringing on some of our Marcellus wells a little later in the second quarter, probably early third quarter now. It's probably going to keep us a little flatter on our production than maybe what we had originally thought about. So I don't think you're going to see a step change in our production profile.

J. Russell Porter

With the caveat that Williams doesn't take any more...

Michael A. Gerlich

Exactly.

J. Russell Porter

Mental vacations.

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

I'm sure they've had plenty.

Operator

And our next question comes from Kim Pacanovsky at MLV & Co.

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

Russ, when you first entered the Hunton, I think I recall that the well costs were about -- or the target was about $4.8 million, and now we're -- you're saying $5.2 million. Am I correct? And what's responsible for that change?

J. Russell Porter

Yes, we -- our initial was $4.8 million, but what is responsible for the current cost is that we went to completions that involved more frac stages.

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

Oh, okay. Okay, great. And you said that you're going to sit back and pause activity. Can you just give us a little bit more color on how long this pause is anticipated for and what you're looking for?

J. Russell Porter

Well, in the Marcellus, we'll not go back to drilling horizontals, so probably January of '14. We may start up our top hole rig in the fourth quarter, so it can get ahead of the lateral rigs. In the Hunton, I don't think this break is going to be very long, to be honest with you, because our plan with our partner has always been to drill East first, 4 wells, evaluate the results. Based on the results so far, it's full speed ahead. But they are going to take the rig over and drill 1 or 2 other wells on some of their other acreage in the area that's outside our AMI, and then we'll resume drilling.

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

Okay, great. And then just last question. What percent of the Chesapeake acreage was really like a Tier 1 type of acreage for the Hunton? Or is it -- you can't even answer that yet.

J. Russell Porter

No, we've evaluated it in that way, and about 70,000 acres of the 157,000 is what we would term Tier 1 for Hunton. Although, as we're now -- our technical team is spending more and more time, and they've got more time to do it now, we're seeing some pretty interesting Mississippi Lime and Woodford potential on parts of the acreage as well.

Operator

Our next caller is Neal Dingmann of SunTrust Company.

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

Say, Russ, what are you -- 2 things just on the Hunton Limestone. First, what are you doing as far as downspacing? I guess, what do you think the opportunity is there? And then secondly, you touched upon this earlier, I think, with Ron. Just on leases having -- as far as holding acreage, what does it look like?

J. Russell Porter

Our spacing, we're trying to drill all of our early wells on 640 acres spacing. We believe that this probably 320-acre drainage that's affected with these wells. On our most recent completion, we did run some microseismic. So we'll have some data that will help us evaluate the completion with a lot more certainty. As far as leases, we're going to get active with the -- we will be very active with the drilling program. We'll hold as many of the leases as possible with production. And the others will extend or renew. A lot of our acreage has got automatic renewals on them. So we're going to be very busy in managing leases, lease expirations and unitization and force pull and all that stuff. It's just part of the program now.

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

Okay. And then, Russ, maybe a question for you or Mike. Just wondering, when you step back a little bit on the other drilling now and see kind of where everything stands, what do you guys want to be, I guess, let's say, at the end of the year as far as on a debt level? And then kind of when you look at liquidity, I mean, you're obviously not too bad right now. But if you bump up the Hunton, where do you see that? I guess I'm kind of looking at the free cash flow. Would you have considered tapping more of the preferred here? Or just maybe, Russ, you or Mike, general thoughts about sort of debt -- ultimate debt level and liquidity.

J. Russell Porter

Well, we'll be financing the acquisition of the Chesapeake stuff shortly. Now we can't say a lot about that right now, but I think once we do that, it will become very apparent to everyone what our cap structure will look like once we get that done. We're not big fans of leverage, but we're not afraid of it either, especially with these type properties where you've got repeatable, low-risk, high return-type opportunities. You certainly can fund that with a portion of leverage, along with your cash flow. I mean, if we're at -- if you look at leverage on net asset coverage basis or you look at it on an EBITDA to interest basis or net debt to total assets, we're not going to stress the company out when it comes to the balance sheet. But I think we do have the capacity to incur some leverage and fund the acquisition and the drilling that we'll do over the next year or so. But we will not be selling common stock, and we have no plans to sell preferred stock as well.

Operator

[Operator Instructions] Our next question comes from Patrick Rigamer with Iberia Capital Partners.

Patrick B. Rigamer - Iberia Capital Partners, Research Division

Not to get too far ahead, but kind of as you look at the Hunton properties, can you talk a little bit about infrastructure and what's there and what needs to be developed and kind of your plans going forward with that?

J. Russell Porter

Frankly, infrastructure is really not an issue there. The oil production is trucked out. There's plenty of trucks. The gas is -- most of it is sold through DCP. They've got a pretty adequate system in place there, both for the early gas purchases when we're running the gaps of compression early on and of course, the gas sales as the wells clean up and we start to see salable gas. So we really are not anticipating infrastructure-type issues in the Hunton play in any way.

Patrick B. Rigamer - Iberia Capital Partners, Research Division

Okay. Good. And then can you just remind me again what the original AMI you have there? It's a 4-well promote. So you guys are finishing that up now. Is that correct or...

J. Russell Porter

Yes, it's a 4-well promote on an initial AMI. There was a promote also on the first 12,500 acres of leases, but we're -- after this well, everything is on a heads-up basis -- I'm sorry, after this well, the promote goes down for the next 4 wells. Then after the eighth well, we're on a heads-up basis.

Operator

And that was our final question. So at this time, I will turn it back to Russ Porter for closing remarks.

J. Russell Porter

All right. We appreciate everyone tuning in to get an update on Gastar. Like we said, it's a pretty exciting time for us here, and we look forward to a very active month or 2 here to get everything closed, the divestiture and the acquisition. And then as always, if anybody's got any additional questions, please feel free to reach out to us here at the office. Thank you.

Operator

Thank you for joining Gastar Exploration's First Quarter Earnings Call. If you wish to listen to a playback of this conference, please dial 1 (800) 804-7944. You may now disconnect.

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