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Gastar Exploration (NYSEMKT:GST)

Q2 2013 Earnings Call

August 06, 2013 10:00 am ET

Executives

Ben Burnham - Vice President of Investor Relations Counsel

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

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

Analysts

Donald P. Crist - Johnson Rice & Company, L.L.C., Research Division

Joel P. Musante - Euro Pacific Capital, Inc., Research Division

Michael Breard - Hodges Capital Management Inc.

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

Joshua Daniel Young - Young Capital Management, LLC

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

Mark Steinman

Operator

Good morning, and thank you for standing by. Welcome to the Gastar Exploration Second Quarter Earnings Call. [Operator Instructions] As a reminder, this conference is being recorded today, August 6, 2013. I would now like to turn the call over to Ben Burnham of Dennard-Lascar Associates. Please go ahead.

Ben Burnham

Thank you, and good morning, everyone. A reminder that 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 Gastar's 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 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. And as a reminder, information reported on this call speaks only as of today, August 6, 2013 so any time-sensitive information may no longer be accurate at the time of a replay. A replay of today's call will be available via webcast by going to the IR section of Gastar's website and also by telephone replay. You can find the replay information in yesterday's news release.

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

J. Russell Porter

Thanks, Ben, and good morning, everyone. Mike Gerlich, our CFO, is with me and he'll have comments on the quarter following my initial remarks. I'd like to begin with brief updates on the recent significant transactions involving our Mid-Continent Oil Play and East Texas assets.

Starting off with the Mid-Continent. On June 7, we closed our purchase of both undeveloped acreage that we believe is highly prospective for the Hunton Limestone formation, as well as producing properties in Oklahoma from Chesapeake Energy. This acquisition included a total of 157,000 net acres, and the purchase price for the acreage improved developed reserves after closing adjustments was about $70 million. In addition, as we've discussed previously, we settled all outstanding litigation for Chesapeake for $1 million, and bought back the 6.8 million shares of Gastar that Chesapeake owned for $1.44 per share, which accounted for another $10 million. The undeveloped acreage we acquired includes oil-rich drilling prospects, with roughly 200 new drilling locations in the Hunton Limestone oil play. That gives us a total of approximately 275 net potential drilling locations in the Hunton, including the existing locations from our original AMI that we are pursuing with another operator, and that exposes us to more than 100 million BOE of net resource potential. These properties initially added approximately 2.8 million barrels of oil equivalent of proved developed producing reserves, of which 18% was oil and 12% was NGLs. We acquired 206 producing wells from Chesapeake with current daily net production of 144 barrels of oil, 50 barrels of NGLs and 3 million cubic feet of natural gas per day.

Subsequent to closing the Chesapeake transaction, we agreed to sell approximately 76,000 net acres in Kingfisher and Canadian Counties that we believe are less prospective for the Hunton Limestone for $62 million in cash subject to customary adjustments. As part of this transaction, we also agreed to trade acreage in Oklahoma with the buyer to allow both companies to block up more contiguous acreage and to optimize development. We are purchasing an additional approximately 1,800 net acres owned by the third party within our core Hunton drilling area. We expect this transaction to close later today. In addition, our partner in the original AMI in Oklahoma elected to exercise its right to acquire approximately 12,800 net acres and 400,000 barrels of oil equivalent of the PDPs that we acquired from Chesapeake for a total of about $12 million.

The results of all these transactions is that we paid about $70 million for the Chesapeake assets. We sold a portion of the acreage and the reserves for $74 million, and we added 68,000 net acres we believe are highly prospective for the Hunton and 2.4 million barrels of oil equivalent of proved developed producing reserves. Plus, in conjunction with the Oklahoma property acquisition, we repurchased about 10% of our stock at a 42% discount to the day before closing market price and 132% discount to the current share price. For the closing of the sale of the non-core Chesapeake acreage, coupled with the anticipated proceeds from the sale of East Texas, Gastar will be in a very strong liquidity position to develop the Hunton acreage and continue our drilling in the Marcellus. In a moment, Mike will talk about the sizable noncash share value gain we realized on our Oklahoma acreage purchase in the second quarter, which boosted our reported net income significantly.

Moving on to East Texas. As we announced a week ago, we have extended the time to close on the sale of our East Texas assets to Cubic Energy for $46 million until as late as August 30, as they're continuing to work on financing arrangements. We continue to remain very hopeful that the deal will close. If we are not able to complete the sale under this latest extension, we would keep at least $3.5 million of nonrefundable deposit money or 7.5% of the total transaction value. As we've discussed previously, the economics of the dry gas deep Bossier wells are not as compelling as our opportunities in the Marcellus and the Hunton based on current natural gas pricing. We don't expect that to change significantly in the near term to medium term. So monetizing our investment at East Texas and redeploying the capital into higher potential areas remains a priority for us.

Before I move on to operational highlights for the quarter, I'd like to touch briefly on our midyear oil and gas reserve position. Since year-end 2012, our proved reserves have increased 38% to almost 249 billion cubic feet equivalent using the SEC prescribed first of the day -- first day of the month pricing formula. The SEC PV-10 value of our reserves increased by almost 57% to $324.1 million. If you use the July 1, 2013 NYMEX forward curve formula, the PV-10 value increases to $432 million. The liquids portion of our proved reserves increased from 28% to 30% over this 6-month period. The Marcellus represented 83% of proved reserve volumes and 85% of PV-10 value. On a volume basis, approximately 82% of the net increase from 2012 is a result of reserve development through the drill bit, and 18% is with PDPs we acquired from Chesapeake. Our midyear reserve report includes East Texas reserves, which were about 11% of the total proved reserve volume, but only 5% of the SEC PV-10 value. You can see more details on this in yesterday's news release. Looking back over the last 2.5 years, I'm proud to say that we have grown our reserve base fivefold from roughly 50 BCF, almost 100% natural gas to nearly 250 BCF equivalent with 30% of our reserves in the form of higher value liquids.

Now moving to operational results of the second quarter, and starting with our activity in the Marcellus Shale and Marshall County, West Virginia. During the second quarter, we brought onto production 10 gross or 5 net operated Marcellus wells from the Addison and Shields pads. That brings the total number of operated Marcellus wells on production to 53 gross or 25 net as of June 30. At the end of the quarter, we also had 7 gross or 3.5 net operated wells that were being completed on the Goudy pad. This week, we will start bringing on production 4 of those Goudy wells for a total -- for a current total gross 57 wells or 27 net operated wells producing from the Marcellus. We're still under a contractual commitment on the drilling rigs. We opted to keep drilling additional wells on the Goudy pad, which delayed the frac-ing and initial sales of the first 4 wells. We still have approximately 113 gross locations we've identified on our existing acreage that are yet to be drilled in Marshall and Wetzel Counties, West Virginia. We anticipate the number of drilling locations will continue to increase as we acquire new leases and swap acreage with other operators in the area.

Net production from the Marcellus increased 56% from the first quarter to an average of 44.2 million cubic feet equivalent per day in Q2. The sequential increase was due to the addition of 10 new gross operated wells, along with a significantly lower level of curtailment due to fewer problems with the third-party operating gathering system. In April, Williams added compression at the Burch Ridge CRP, which has decreased line pressures. We're still struggling with occasional high line pressures and unscheduled downtime, but we have seen improvement. As you'll remember, last quarter, we estimated that 40% of our Marcellus production was curtailed due to gathering system problems. That decreased to approximately 13% for the second quarter. Mike will provide additional detail on the financial impact of this in just a moment.

Condensate yields were 33 barrels per million cubic feet of gas in Q2, and NGLs yields were 48 million barrels per million cubic feet. We anticipate that our condensate yields will continue to improve, as our development drilling moves West as we continue development. With the initial Goudy wells now complete, we're going to take a short break from new drilling in the Marcellus to observe the results of the tighter well spacing we've tested on the Goudy pad. As you'll recall, we also experimented with different lateral estimates [ph] on 5 wells on the Addison pad. Our initial evaluation of those wells indicates that there's no difference in results from this well design. So going forward, we have greater flexibility to develop our acreage by orientating the wells to better match the size and shape of the acreage blocks, compromising each drilling unit. The short break in drilling will also give Williams additional time to continue upgrading their system, and hopefully improve volume throughput and reduce downtime. Access to Williams fractionation capacity and pressure stabilization of our condensate, as required under our agreements, would also greatly improve the price realizations for our NGLs and condensate.

By September, we plan to bring back a small rig to the Marcellus to drill top holes and then bring in a larger rig in January to drill laterals. This is the same strategy we successfully used to minimize development costs in the past. The average gross total drill and complete cost for our last 2 Marcellus horizontal well pads based on average laterals of 5,000 feet was approximately $6.7 million, including the cost of the pad and facilities. Our Marcellus program is going very well, but we continue to look for opportunities to expand and optimize our acreage position. We spent approximately $19 million in CapEx in the Marcellus in Q2, and we expect to spend an additional $15.4 million in the second half of the year, including $4 million for land acquisition costs.

Looking next at the Hunton oil play in Oklahoma. We participated in the drilling of a total of 5 gross non-operated wells so far in our original AMI area that includes acreage in Kingfisher and Garfield Counties. Our second Hunton well continues to perform very well. Flowback began in mid-February, and it's currently producing a gross rate of 771 barrels of oil equivalent per day, about 63% of which is crude oil. This well has already cum-ed 154,000 barrels of oil equivalent, and based on a third-party engineer evaluation, is projected to have an estimated ultimate recovery of 740,000 barrels of oil equivalent.

Our third Hunton well began flowback in early April. Initial flowback on the well was delayed as a result of problems with a gas lift compressor. The compressor issue has been resolved, and we are now watching production closely. The well's currently producing about 78 BOE per day, of which 90% is oil. This production rate is less than we had expected, but we believe that production will improve. The well is currently averaging about 540 barrels of completion fluid per day so there appears to be plenty of energy within the reservoir. As of today, about 35% of the completion fluids have been recovered.

The Mid-Con 4H well began to flow back in May and was initially flowing in excess of 3,100 barrels of completion fluid per day. Frac sand flowed back into the well bore, and we just successfully completed coiled tubing operations to clean out the lateral. The well was just returned to production, and is cleaning up nicely with increasing production. And during the past 4 days, it averaged 95 barrels of oil, 230 MCF natural gas and 740 barrels of completion fluid per day. Today, we received back approximately 29% of the completion fluids. The 5H well is still in process. We reached total depth in late January, and we expect begin completion operations by the end of this week, and we're scheduled to put it on flowback later this month.

We are currently spudding our sixth nonoperated well in the original AMI, and are participating in one other non-operated horizontal Hunton well outside the AMI with a different private operator. This will be that private operator's 20th horizontal Hunton well. Based on conversations with the operator, they are experiencing well results similar to our type curve, and we are looking to gain additional knowledge on drilling and completion through this participation. In general, we have seen a significant increase in Hunton, Woodford shale and even Mississippi Lime drilling in and around the acreage we acquired. On the new acreage we acquired from Chesapeake, we're initially targeting 3 operated wells, with the first well to spud by October, with the flowback scheduled to begin in early December. We plan to run 1 operated drilling rig through the rest of this year and into early 2014. With 5 non-operated Hunton wells under our belt, we are now evaluating the drilling and completion process previously used as we move into drilling gas at our operated Hunton wells. Based on our planned drilling and completion approach, we estimate that our gross operated wells drilling completion cost will average about $4.5 million each. And with time, we hope to further improve on that cost. We expect the Hunton cost reductions to be realized by applying the horizontal drilling techniques that have worked well for us in the Marcellus. Excluding the acquisition costs, we spent $8.5 million in CapEx in Oklahoma in Q2, and we expect to spend an additional $39.6 million in the second half, of which $10.5 million is for acreage acquisitions and renewals.

I'll now turn it over to Mike to go through financial details, and I'll be back with a few other comments.

Michael A. Gerlich

Thanks, Russ, and good morning, everyone. As usual, I'll begin with the highlights from yesterday's news release, then cover expense trends and provide guidance for the third quarter.

Looking first at the top line. Second quarter revenue from natural gas condensate and oil and NGLs production increased 111% from a year ago to 23.4 million. This was due in part to a 65% year-over-year increase in production, mostly from growth in the Marcellus Shale, plus the contribution from the Oklahoma wells we drilled, and production for 3 weeks of June from the wells we acquired from Chesapeake. These increases were slightly offset by natural declines in our East Texas dry gas production. The continued benefit from the growing portion of higher value oil condensate and NGLs in our production mix, which grew to 49% of our total revenues before unrealized hedge impacts versus 46% in the first quarter and 40% a year ago. Higher Q2 revenues also benefited from a 28% year-over-year increase in our average realized commodity price, which increased from $3.51 a year ago to $4.48 in the second quarter, including the impact of realized hedging activities. Approximately 76% of our natural gas production, 29% of our condensate and oil and 50% of our NGLs production was hedged during the second quarter. We continue to look for opportunities to enhance our hedge positions. You can find complete details about our hedging program as of June 30 in our 10-Q filed yesterday afternoon.

Turning now to our bottom line results. On an adjusted basis, net income attributable to common shareholders for the second quarter was $3.2 million or $0.05 per diluted share compared to an adjusted net loss of $4.1 million or $0.06 per share a year ago. On a reported basis, including the positive impact of special items, totaling a net $48.6 million, net income was $51.8 million or $0.81 per diluted share in the second quarter. That compares to a reported net loss in the second quarter of last year of $74 million or $1.17 a share due primarily to a $72.7 million ceiling impairment. In the current quarter, our reported results benefited from a $43.7 million non-cash fair value gain related to the acquisition of the Chesapeake oil and gas properties and undeveloped leases, which I'll come back to with more detail in moment and a $7.5 million unrealized hedging gain. These gains were partially offset by $1.4 million of nonrecurring transaction cost included in G&A related to the Chesapeake property acquisition and $1.2 million included in interest expense and write-offs relating to deferred fees for our old revolving credit facility, which we replaced with a new facility in early June led by a new bank group. The $43.7 million gain on the Chesapeake assets is a noncash gain as a result of a new accounting procedure requiring that acquisitions be recorded at fair value at the date of closing. We commissioned a third-party fair value measurement of the Chesapeake assets, which resulted in an estimated value of $113.5 million. As a result, accounting rules required us to recognize a gain on purchase of $43.7 million.

As Russ covered earlier, excluding the amounts we paid to Chesapeake to settle litigation and to buyback Gastar shares, we paid about $70 million for the oil and gas assets. About $40 million of that represented payment for undeveloped acreage, and the remainder for the proved developed producing reserves. We are selling a portion of the non-core acreage for $62 million and received another $12 million based on our partner's AMI election. In summary, we paid $70 million to buy the oil and gas assets in order to receive about $74 million for a portion of the oil and gas assets. After sale, we'll still own about 68,000 net acres and 2.4 million BOE of PDP reserves acquired in the Chesapeake transaction.

Personally, I'm not a real believer in fair market value gain recognition on the purchase since it's truly an estimate and noncash, but in our case, the gain is subsequently supported by the related partial asset sales. Note that under full cost accounting, the asset sale proceeds will be credited primarily to unproven property cost.

Changing focus, second quarter adjusted cash flow from operations increased to $12.3 million or $0.19 per diluted share compared to $3.7 million or $0.06 per share a year ago and $13.1 million or $0.21 per diluted share in the first quarter. The sequential decrease in cash flow was a result of higher dividends of $400,000 on a cash basis and interest expense of $1.6 million due to new debt facilities.

Looking at production. Combined average daily production was 57.6 million cubic feet equivalent, which exceeded our guidance of 52 to 55 Mmcfe per day. I should note that in estimating production guidance last quarter, we had expected the East Texas sale to close by early June so we had factored in just 2 months of production from East Texas. If you net out the additional month of East Texas production, we would have come in at 54.8 MMcfe per day, right on target with the upper end of guidance.

Average daily production increased 42% from the first quarter. This was primarily driven by production from new wells in Marcellus, the lower Marcellus third-party midstream curtailment issues and the Hunton production, partially offset by natural declines in East Texas. As Russ noted, we estimate gathering system issues reduced second quarter 2013 production by approximately 17.6 million cubic feet equivalent per day or 13% of total production versus 16.4 million a day or 40% of total production in the first quarter of 2013. So the situation there is improving. The estimated gathering system issues impact on cash flow in Q2 was $2.8 million compared to $6.4 million in Q1. Condensate, oil and NGLs represented 29% of our production, which was below our guidance of 30% to 34% and compares to 26% in the first quarter. Had we closed the East Texas sale by our target date, the percentage of liquids would have been about 31%.

Looking at production guidance for the third quarter. Assuming no more than 8% pipeline related curtailment of our Marcellus production and that we lose about 9 million cubic feet equivalent per day of East Texas dry gas production by mid-August, which is the current target date for closing, our total company production for the third quarter is 50 million to 54 million cubic feet equivalent per day. As a result of the ultrarich gas production West Virginia and the elimination of the dry Texas gas production in the quarter, we expect the percentage of condensate oil and NGLs to increase to between 31% and 34% of total production in the third quarter.

Looking next at some of the key expense items in the second quarter. Our lease operating expense was $2.2 million, which was the midpoint of our guidance range of $2 million to $2.4 million. That compared to LOE of $1.6 million a year ago and $1.8 million in the first quarter. The delay in the sale of East Texas increased LOE costs for the quarter by about $300,000. On a per-Mcf equivalent basis, lease operating expense declined to $0.41 per Mcfe versus $0.49 a year ago and $0.50 in the first quarter. The decrease in per unit costs was due to higher production volumes from new wells on production in West Virginia and Oklahoma. For the third quarter, we expect LOE to be in the range of $2.4 million to $2.8 million primarily due to full quarter impact of Oklahoma property acquisition.

Production taxes were $1.2 million versus $481,000 in the second quarter of last year. This is a result of higher production of the Marcellus, which unlike East Texas, is not exempt from production taxes. We received a tight sands credit for Texas production, but as our revenues continue to grow in West Virginia and Oklahoma, production taxes will continue to grow based on each of these states' tax rates, although Oklahoma does allow for reduction in the production tax rate from 7% to 1% for new horizontal wells for the first 4 years of production. Our future Hunton horizontal drilling will benefit from this tax exemption.

The DD&A rate per MCF equivalent was $1.45 in the second quarter versus $2.20 a year ago and $1.47 in the first quarter. The year-over-year decline was due to lower proved costs, resulting from $151 million of ceiling impairments we booked in the second and third quarters of last year, along with higher proved reserves.

Transportation, treating and gathering expense was $1.1 million, which was a little above our guidance of $800,000 to $1 million. Again, our guidance had anticipated closing the sale of East Texas properties by early June. This expense would have been at the bottom end of our guidance range without the additional East Texas expense for June. East Texas represented about $940,000 of the second quarter total expense. If we close the East Texas sales, as now expected in mid-August, that would put our third quarter transportation treating and gathering expense at around $600,000 to $800,000, declining to a range of $200,000 to $300,000 per quarter thereafter.

Cash G&A expense was $3.8 million. Approximately $1.4 million of that was onetime cost related to the Chesapeake asset acquisition that must be expensed and not capitalized. Excluding those costs, we were within the upper end of our guidance range of $2.2 million to $2.5 million and up about $200,000 from the first quarter. For the third quarter, we expect cash G&A of about $2.5 million to $2.9 million. This amount factors in employee severance cost of about $500,000 related to the East Texas sale.

Non-cash stock compensation expense was $1.1 million, which is up $320,000 from the first quarter and slightly above our guidance range of $800,000 to $1 million. For the third quarter, we expect noncash stock compensation of about $1 million to $1.2 million.

Looking at the balance sheet. At June 30, we had cash and cash equivalents of $10.8 million and outstanding long-term debt of $194.6 million with a face value of $200 million. As we previously reported, on May 15, Gastar U.S.A. issued $200 million of 8 5/8% second lien notes due May 2018. After transaction-related fees and expenses, we netted about $194.5 million from that offering. In conjunction with the second lien financing, our revolving credit facility borrowing base was decreased to $50 million with a maturity date of November 2017. We currently have 0 outstanding on the revolver. Future growth of revolver borrowing base is limited to 17.5% of growth in adjusted consolidated net tangible assets or ACNTA. With the pending close of the Oklahoma and East Texas sale, we are not projecting any near-term revolver borrowings based on current capital spending forecast.

Capital expenditures invested in the second quarter, excluding acquisition, was about $29 million as compared to $35 million in Q1. The decrease in spending reflects the fact that we ratcheted back new drilling in the second quarter in the Marcellus to evaluate the results of the spacing enhancement test that Russ discussed earlier. For the remainder of the year, we expect to spend about $60 million, which will put us at a total of about $124 million for the full quarter excluding acquisitions. The net increase of $22 million is primarily due to additional spending in the Hunton of $17.5 million for drilling and $8 million for land, partially offset by reductions due to timing in other areas. Including acquisitions, our total 2013 spending estimated to be $193 million before the previously discussed asset sale proceeds of about $108 million. Out of the 2013 remaining $60 million of capital expenditures, $40 million is for drilling completion and infrastructure; $15 million is for leasing and seismic; and $5 million is for other capitalized cost. Looking at remaining capital expenditures for this year geographically, excluding other capitalized costs, $15 million is allocated to the Marcellus and $40 million is earmarked for the Hunton Limestone.

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

J. Russell Porter

Thanks, Mike. I'd like to emphasize how important the developments over the last 4 months are to our near-term outlook and our long-term opportunities to build additional value for our shareholders. The capital market's response to the series of announcements of very strategic transactions and investments has been gratifying. I'm pleased to say that since April 1, when we announced the Chesapeake transaction, our common share price has increased by approximately 89% from $1.76 at the end of March to $3.34 as of yesterday's close. Between the new opportunities for oil exploration and development in the Hunton Limestone and Oklahoma, where we began leasing just 1.5 years ago and our continued development of the ultrarich natural gas in the Marcellus Shale of West Virginia, Gastar is extremely well positioned to benefit from the relative strength of liquids prices. If we complete the sale of our East Texas dry gas assets, our production profile is projected to be approximately 64% natural gas and 36% oil condensate and NGLs. We believe the Hunton could be an exciting new oil play with very good economics. Like we did in the Marcellus, we got in early in a big way and at a low-cost. We believe that we have developed a solid track record for systematically enhancing the economics of our projects by continuously refining the drilling and completion costs, while also closely managing other costs. We'll be applying the lessons we've learned and our dedication to achieving success to this new project in Oklahoma. We look forward to testing the potential with our new operated acreage starting next month.

That concludes our prepared remarks. At this time, operator, we are ready for Q&A.

Question-and-Answer Session

Operator

[Operator Instructions] And our first question today comes from Ron Mills of Johnson Rice.

Donald P. Crist - Johnson Rice & Company, L.L.C., Research Division

Actually this is Don. Starting in the Marcellus, can you give us -- I think I missed it in your prepared remarks, the total inventory that you have currently on current well space and the impact of the azimuth changes that are possible now, and the possible 400-foot spacing that's going forward, assuming that works on the Goudy pad?

J. Russell Porter

Yes, on current acreage, as we stand today, we've got another 113 gross locations to drill, and that's just Marshall and Wetzel counties that assumes the 400-foot spacing, which appears it will be successful going forward. We're still adding acreage. We're swapping acreage with other operators in the area. So I think that gross number of well locations will eventually get up to somewhere in the 140, 150 range based on what we're working on today.

Donald P. Crist - Johnson Rice & Company, L.L.C., Research Division

Okay. And turning to the Hunton, on the 3 and the 4 wells, can you tell us where the laterals were placed on those wells? And if they're any different from the 2H and the 1H that you've already done and where those shake out compared to your original type curve?

J. Russell Porter

The 1H was drilled in the middle Hunton. The 2H, 3H and 4H have all been drilled in the lower portion of the play. As far as how they compare to the type curve, the 1H is significantly below it. For 2H is essentially twice the type curve. The 3H and 4H, the 3H is -- more of the fluid has been recovered on it, and the oil has been pretty steady, but we don't see as much gas in that well for some reason. So I'd say it's not likely to get to the type curve. But the 4H, after we've cleaned out the well bore and are starting to see significantly more gas production with the oil production increasing, certainly, the jury's still out on it, but it's looking better and better each day. The 5H, we just got through drilling, and we're encouraged by what we saw on that as far as it shows during drilling, and we're going to start completion of it immediately. So we think we've got a pretty good start on this play. I think the real test ought to be once we start operating our own wells, which we'll do in late September or October, and give us 4 or 5 wells that we've operated where we've chosen all the locations and done all the work, and then I think we really have a good feel for the play.

Donald P. Crist - Johnson Rice & Company, L.L.C., Research Division

Right, and just one more, if I may, for Mike. Can you -- assuming that all the transactions get done in the next few days and you close the Cubic deal on the 16th, can you talk about pro forma liquidity going forward, how much cash you'll have on the balance sheet?

Michael A. Gerlich

Sure. Assuming both of these transactions close, looking at where we ended for the second quarter, we'd have about $120 million of cash, $50 million unused revolver, and that would be the breadth of our liquidity. Obviously, that would be very strong position for us.

J. Russell Porter

And the $50 million, that does not include the effects of the recent reserve adds we've made. So if we calculate it up, we can -- we might be able to increase that sum as well.

Operator

And our next question comes from Neal Dingmann at SunTrust.

Unknown Analyst

This is Will [ph] for Neal. Quick question, kind of looking at the gathering issues in Marshall County, obviously good to see some improvement there. But what's the timeline, going forward, for any further relief? How should we look at that?

J. Russell Porter

That's a good question. We've been working with them for 18 months now, and we've not been satisfied with any of the timing on any of the improvements they've made. It's -- right now what they really need to do is increase their ability to handle condensate so that we cannot have the system go down because of condensate handling issues. And frankly, they need to start utilizing the fractionation assets that they've got in place to give us better fractionizations on our NGLs, and I really don't have a good answer for you when either those things could occur.

Unknown Analyst

Okay, all right. And then also kind of going to your -- looking at the type curve for your Marcellus West in your slides, how are kind of your recent wells, I guess, really, wells in the last 6 months, looking relative to that 6.3 Bcf curve you have?

J. Russell Porter

Our new type curve based on the results we've seen is actually 6.7 BCF equivalent EUR, 66% gas; 34% liquids with a cost of $6.7 million for a 5,000-foot lateral.

Unknown Analyst

Okay, and so recent completions are kind of in line with that?

J. Russell Porter

Oh, absolutely, yes.

Operator

And our next question comes from Joel Musante at Euro Pacific Capital.

Joel P. Musante - Euro Pacific Capital, Inc., Research Division

Russ, yes, just had a question about your type curve. Can you just describe the production rate over the flowback period for your type curve wells in the Hunton?

J. Russell Porter

Production rate over flowback period?

Joel P. Musante - Euro Pacific Capital, Inc., Research Division

Yes, like what they come on at and how they ramp up over time.

J. Russell Porter

The peak, our type curve, we're looking for about 400 barrel a day IP or peak rate, I should say, more than IP, and just under 1 million cubic feet of gas a day. What we're seeing is that the wells will build up to that over anywhere from 2 weeks to 6 weeks once we put them on production. It just depends on really what the porosity in the reservoir is like, and how many fractures we've accessed, whether we've accessed any primary porosity and -- or if it's all just fracture related. And as we look at all the other wells that we have information on, plus with surrounding operations or surrounding operators, it appears that they performed about the same way. So you put these online, you'll get them up to about 400 barrels a day for an average well and just over 1 million cubic feet a day over 2 to 6 weeks.

Joel P. Musante - Euro Pacific Capital, Inc., Research Division

Okay, all right. So the last, I guess, 6 or 7 wells drilled by your partner seem to follow that same trend?

J. Russell Porter

That's correct.

Joel P. Musante - Euro Pacific Capital, Inc., Research Division

Okay, all right. And then just looking at the reserves, did you -- I think I read that most of the PUDs were booked in the Marcellus. Is that correct -- or all of them?

J. Russell Porter

That is correct?

Michael A. Gerlich

Yes, all of them were booked in the Marcellus.

Joel P. Musante - Euro Pacific Capital, Inc., Research Division

Okay. Is there any reason why they didn't -- they selected not to book any PUDs in the Hunton at this point?

J. Russell Porter

I think they just were looking for more production history and looking better at our subsequent well activity. We do anticipate we'll be booking PUDs come year end out there. It was just early on in the development program, and the third-party engineer just was looking for additional data points before they would look at booking PUDs.

Operator

[Operator Instructions] Our next question comes from Mike Breard at Hodges Capital.

Michael Breard - Hodges Capital Management Inc.

On your East Texas sale, the timing has been extended to August 16 with an option to go to August 30. What do you -- how do you assess the odds of that actually closing in August? And if not, do you have a plan B that could possibly close with somebody else maybe in October?

J. Russell Porter

As far as assessing the odds, I had a conversation this morning, and I was told that Cubic has now got their financing term sheet executed, and they expect to close before -- on or before August 15, 16. So they expect that they would not have to put up the additional deposits to extend that further. I mean, it comes from a reputable source, and we've spoken with the people that are providing their financing, and we've assisted in their due diligence as requested. So I think it's highly likely that the transaction will close.

Operator

Our next question comes from Hoshang of MLV.

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

Can you highlight your Hunton program and number of gross wells that you've planned for the Hunton and the CapEx going forward, just a recap?

J. Russell Porter

I'll let Mike touch on CapEx. I've got -- we've got 3 operating wells we'll drilled between now and the end of the year, with the first one coming online probably later -- at least in the late portion of the year. We'll drill -- probably we have 1 rig running most of next year. We'll have -- it's looking like somewhere 8 wells that we'll operate and then probably a similar number that will be drilled on a non-op basis. In addition, we've also got some wells that are difficult to schedule because of forced pooling. We expect to be -- to receive forced pooling orders and participate in some other non-op wells that are difficult to project right now.

Michael A. Gerlich

From a total expenditure standpoint, as we described earlier, we're looking to spend about $40 million in the second half of this year. The breakout of that is about $12 million on land. $1.5 million of that, we'll be spending here today with the closure on that sale of the non-core acreage. As Russ had mentioned, we're purchasing about 1,800 acres that, that party owns in our Tier 1 area, and the other $28 million is really the drilling aspect of it, as Russ described.

J. Russell Porter

And Hoshang, I have to tell you, we're very early on in a very large position in the Hunton and a position we've got at extremely low cost. The industry activity around us is increasing very rapidly, and we're really very, very optimistic about this play. It really is early days, and we're just beginning evaluation of it.

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

All right. And just a follow-up, on those 3 operated planned wells, gross wells, are they close to your 2H well or they're all scattered all over the place? Because I understand that's a very large position that you have. Do you -- what are you looking at? Where is the plan there?

J. Russell Porter

We're looking at -- one of the wells is in the heart of the area that our operating partner has drilled most of their successful wells. One is between the 2H and that area, and one is all the way down south in Canadian County, and our region there is we're going to really test all 4 corners of our acreage position with the activity that will take place over the next 6 to 12 months.

Operator

And our next call comes from Murray Scheinker [ph] of Scheinker Investments.

Unknown Shareholder

Let me take a moment to comment. I'm also a very happy shareholder in Gastar, and I know all the questions today are technical, the oil and gas production. And earlier, you had comments about very happy the increase in the share price of our stock. All the analysts are going to go back and write up the Gastar and their questions and answers in the report, and give their opinion on the price of Gastar's stock, high and low, good or bad. I wonder if management of Gastar would also comment in a way. And my question is, if a company today would offer Gastar a price to be bought out, what in your opinion would be the minimum price, the value of this company's share to be bought out? Can you comment as management? I only hear analysts always comment about the price of a share and the value, good, bad or indifferent, it's their opinion. I think management is so important, and they honestly know the great and true value of a share. What would be the buyout minimum you would accept? It would give me an idea of the value of our share price today.

J. Russell Porter

We would have evaluate any offer probably on the basis of not only a multiple of cash flow, but also NAV analysis. And if you look at our net asset value range, if you look at it simply on proved reserves that exist today on NYMEX pricing, undeveloped acreage at market prices, deduct all the balance sheet items, including the negative working capital and treat the preferred stock as if it were debt, that would probably give you NAV somewhere in the low 4s. If you include the very low risk Marcellus development in with that, beyond proven reserves, it could get you up into $5, $6, $7 a share. So it would be -- the board will evaluate those type of issues, market conditions, capital markets, likelihood of increased financing needs, et cetera. All that goes into the soup when you evaluate an offer like that. So I really couldn't tell you a minimum price. I can just tell you the factors we would look at in evaluating the price.

Operator

Our next question comes from Josh Young at Young Capital.

Joshua Daniel Young - Young Capital Management, LLC

So just to clarify, it sounded like you said that there was going to be another Hunton operator, another private operator that was going to drill a well that you're going to participate in, and it sounded like you said that, that operator had another 20 results in the Hunton that they achieved on their own?

J. Russell Porter

That's correct.

Joshua Daniel Young - Young Capital Management, LLC

And is that -- where are they active relative to where you guys have participated so far?

J. Russell Porter

They are more active down in the area where our operating partners drill most of their wells. They've been active in the area where a good portion of the acreage we acquired from Chesapeake lies. So they're -- it's also the same area where 1 of our 3 initial operated wells will be drilled.

Joshua Daniel Young - Young Capital Management, LLC

Okay. So I mean, this is really significant, right? Because doesn't this substantially de-risk the type curve. So I know we're all trying to project out what Hunton could do based on your guys' 4 results that you shared to date, but it sounds like there might be well over 40 industry results so far in the horizontal Hunton. Is that a reasonable way to look at it?

J. Russell Porter

It is. We've used about 20 wells that we've got first-hand data on to generate our type curve. But everything we're seeing from other operators in the area, their reported production rates and discussions with them also support the type curve that we're using.

Joshua Daniel Young - Young Capital Management, LLC

How many -- and just one more follow-up. How many wells do you think so far, at least, that you guys are aware of have been drilled into the horizontal Hunton and the play that you're going for in the general area that you guys are active in?

J. Russell Porter

Josh, I'd say it's probably in the 40 to 50 range right now.

Operator

And we have a follow-up question from Ron Mills at Johnson Rice.

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

All of my questions have been answered. Thanks, guys.

Operator

And our final question comes from Mark Steinman at Raymond James.

Mark Steinman

I was wondering if you guys could comment on if you have any knowledge of the current SEC inquiry into LINN Energy and their hedging, and if that is, at all, of concern to you guys? And if you could further any thoughts on how you think that might play out, that would be great.

J. Russell Porter

We're not versed in LINN Energy's hedging issues. So we really would not be in a position to make any comment on those. I really don't have anything to add.

Operator

Thank you, and at this time, we do not have any more questions. So I will turn it back to management at this time.

J. Russell Porter

Okay. We appreciate everyone taking the time to join us for this update. This is a pivotal period for us in terms of positioning Gastar for value growth over the next several years, and we'll look forward to updating you again on the third quarter call. Thank you.

Operator

Thank you for joining the Gastar Exploration Second Quarter Earnings Conference 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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