Gastar Exploration's (GST) CEO Russ Porter on Q1 2014 Results - Earnings Call Transcript

| About: Gastar Exploration (GST)

Gastar Exploration, Inc. (NYSEMKT:GST)

Q1 2014 Earnings Call

May 8, 2014 10:00 a.m. ET


Lisa Elliott – Dennard-Lascar Associates

Russ Porter – President and CEO

Mike Gerlich – SVP and CFO

Mike McCown – SVP and COO


Kim Pacanovsky – Imperial Capital, LLC

Gabriele Sorbara – Topeka Capital Markets

Neal Dingmann – SunTrust Robinson Humphrey, Inc.

Don Crist – Johnson Rice & Company

Jason Wangler – Wunderlich Securities


Good morning and thank you for standing by. Welcome to the Gastar Exploration First Quarter 2014 Earnings. At this time everyone is in listen-only mode. (Operator Instructions) As a reminder, this conference is being recorded today, May 8, 2014. I would now like to turn the call over to Lisa Elliott of Dennard-Lascar Associates. Please go ahead.

Lisa Elliott

Thank you, and good morning, everyone. Today's call will contain forward-looking statements, and although management believes these statements are based on reasonable expectations, they can give no assurances that they will prove to be correct. These statements are subject to certain risks, uncertainties and assumptions as described in the company's Form 10-K from 2013 filed on March 13, 2014 and subsequent SEC filings, 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.

As a reminder, information reported on this call speaks only as of today, May 8, 2014, so any time sensitive information may no longer be accurate at the time of the 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 a 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?

Russ Porter

Thanks, Lisa. Good morning, everyone, and thanks for joining us on the call. Mike Gerlich, our CFO, is with me, and he will review a few key financial items following my initial remarks. Mike McCown, our COO, is also on the line and will be available during the Q&A session.

We posted a solid quarter with a 43% year-over-year increase in production which drove a 187% increase in total revenues including the impact of our hedging activity and a 71% increase in adjusted EBITDA. For the remainder of the year, we're going to focus on balancing our goals of increasing production and cash flow, while also pursuing opportunities to grow reserves and more fully evaluate the potential on our asset base.

In Appalachia and in the mid-continent we plan to test new formations on our existing acreage positions. We expect it to be an exciting year, which will gather important information to help us evaluate how best to optimize the value of our significant asset base. We are currently drilling our first Utica-Point Pleasant horizontal exploration well in Marshall County, West Virginia.

It's located in the north central portion of Marshall Country acreage. We expect well production results by early third quarter. Based on our internal analysis and the supporting results of other Utica-Point Pleasant recently drilled by nearby operators. We're very optimistic about the potential for this well.

In the late third quarter, we are currently planning to move our West Virginia south to Wetzel County, West Virginia to commence drilling of two Marcellus wells and one Utica-Point Pleasant well. We expect the Marcellus formation of Wetzel County to be just as productive and to have equally high liquids content as the Marcellus formation in Marshall County, where we've previously been concentrating our efforts.

We are also looking forward to the results of our Utica test in Marshall County. Based on offset results to-date, we are encouraged of the Utica-Point Pleasant formation in Wetzel County, it could be even more productive then in Marshall County because the Utica formation is deeper than the Marcellus at about 11,100 feet verse 6,500 feet.

The Utica-Point Pleasant will give us more information about the Marcellus. As we drill through the Marcellus, we will gather long data to evaluate it. Plus the success Utica drilling program would not validate approximately 1,800 gross Utica drilling locations assuming a 1,000 space in between well bores, but it would accelerate the transfer of over 171 gross probably Marcellus location that proven undeveloped in Marshall and Wetzel counties.

Our Marcellus development program is still active in Marshall County with 10 gross wells expected to be completed in the second half of 2014. We had expected to put three wells from our Goudy pad on production, the second quarter but those are being delayed pending the resolution of a non-lessee or surface owner issue.

In our Mid-Continent Hunton play, oil play in Oklahoma. We are continuing our early stage exploration development of the Lower Hunton Formation and planning on testing the upper Hunton, the Woodford Shale and the Meramec formations commencing later this year.

We are currently drilling our first lower Hunton Well, the eastern number 22-1H on our recently acquired WEHLU property and should have initial results early in the third quarter. We drilled a vertical pilot hole for this well and saw a strong shows along with porosity and the upper, middle and lower Hunton formations.

We just reached total depth on this well on the horizontal well this morning. After logging occasion this well, we will immediately skip the drilling rig and drill a horizontal Bois d'Arc or upper Hunton well from the same pad and then complete both wells.

As a reminder, we attributed no proven reserves to the lower Hunton, when we acquired the WEHLU property and currently have 44 lower Hunton probable locations, identified only 7,000 of this 24,000 net acre unit. Obviously, the successful well in the lower Hunton could add a significant and proved value to the WEHLU asset.

We are working and determined the optimal way to drill and complete our lower Hunton wells particularly the ones that are highly fractured. Challenges and the drilling and completion of the highly fractured Hunton Formation affected our third operated well, that's a [Borex] 22-1H and caused us to drill a shorter lateral section than originally planned.

With the [boric] well recent IP of 236 Boe per day, 40% crude oil from this shortened 3,000 foot lateral section and because of the drilling issues. We encountered, we estimate only about 2,000 feet of the lateral was actually in the target of the Hunton formation.

We are going to proceed carefully with our operated lower Hunton drilling program and make sure; we can pick the time to evaluate the results. We've achieved today and focus on the optimizing, the drilling and completion techniques for future wells. Operations with our joint venture partner are continuing in an active pace.

Production on three wells, the Jet, the [Lepard] and the [Cornado] completed during the quarter continue to show production improvement, while still flowing back significant volumes of completion fluids. Currently daily average production on these wells is about 140 Boe, 81% oil and 207 barrels of completion fluid per day. To-date these wells are produced on average 14% of the completion fluids.

We believe that wells that reach an IP on the slower track approximately one-third tour wells that reached an IP on a slower track approximately of the completion fluid it has to be produce before we can judge the ultimate performance of those wells.

Three additional wells, [Gainberg], Jones and Rosemary appear to have reach IPs averaging 482 Boe per day, 74% oil. Control back of completion fluids on these wells is currently averaging 508 barrels a day and the wells have averaged 23% of produce completion fluids.

Though, the IPs are 80% of our target tight curve rate, all production percentage is about 14% higher than the tight curve. We realize, the market has a tendency to just focus on the most recently well results, but we've always stated that the hotness of statistical play.

The average of the 11 JV partnered wells with reported IPs to-date is 613 Boe per day was 73% oil versus our tight curve IP of 608 Boe per day, 65% oil. Thus far, we have a high degree of confidence in the Hunton Play. We've resolved our operated drilling and completion challenges and should be able to drive down drilling cost.

Looking at current inclusion and drilling activity in the JV area. Flow back on the Seabird and Kodiak wells commenced April 13 and May 4 respectively. Drilling and completion operations are underway on an additional four other wells.

We will release well results as warranted. Please see our 10-Q filed yesterday for additional well information regarding current Hunton activities. Following the drilling of the upper Hunton well on the WEHLU acreage. We will drill another operated lower Hunton well in Canadian County and then we will focus our operated Mid-Continent activity to test and de-risk the Woodford Shale and Meramec formations i.e. the stock play.

To support this effort, we've taken steps to accelerate the timing for testing these formations. Recently we signed approximately 9,600 gross or 4,200 net acres in a non-quarry area in Kingfisher County to a third-party operator. In addition to a cash payment to-date of $3 million, the third-party is required to drill two Woodford Shale well test by July 31, 2015 or pay us an additional $300,000.

The first Woodford Shale test must be spotted by September 1, 2014. Though, we will not receive any of the production from these wells. We will benefit from the valuable well data that will help us determine on a cost-free basis. The stack play potential in this area.

Under the checkerboard pattern, acreage assignment approach. We held onto an adjacent acreage inner spruced in the area. We should greatly reduce the drilling risk on offsetting acreage. Depending on the success of the third-party operators drilling. We may have the potential to book proven under off reserves on our offsetting acreage, based on their drilling results.

Also, as we previously mentioned we have a very small interest in the Canadian County Woodford well drilled by QEP, that we expect will be completed in the near term. In addition, we plan to drill on operated horizontal Woodford Shale test this fall. The well depth is expected to be approximately 9,100 feet with a lateral length of up to 10,000 feet for an estimated gross cost of $10 million to $12 million.

Our ultimate working interest in the well will not be determined until the well is permitted and forced pooling hearings are complete. If successful, first production of this well is expected in the third quarter of 2014. We believe that we approximately 24,000 net acres for their perspective for the Woodford Shale that could accommodate approximately 200 net wells.

Our first Meramec Formation test is currently scheduled for the fourth quarter of 2014 in Kingfisher County. The Meramec is slightly shallower than the Woodford Shale. The well we are planning is expected to be approximately 7,500 feet deep with a planned 10,000 foot lateral and an estimated gross cost of $10 million to $12 million.

Again, we want our working interest in the well until permitting forced pooling hearings are completed. If successful, first production from this well will be late fourth quarter, 2014. In addition, new field exploration and other operator with nearby acreage have reported impressive results in the Meramec as part of their stack play.

We believe that we have approximately 60,000 net acres for their perspective for the Meramec and could accommodate approximately 300 net wells. The finer Woodford Shale and or Meramec test. We are reviewing the possibility of redirecting, a portion of our operated Hunton Capital to these efforts rather than increasing our Mid-Continent drilling capital program.

Successful Woodford and Meramec drilling not only gives us additional reserve upside, which was not originally contemplated in our Chesapeake acquisition but will give us additional time to evaluate the performance of our Hunton wells and optimize our drilling completion procedures for future Hunton Wells.

And I will turn it over to Mike, to go through the details and I will be back with a following remarks.

Mike Gerlich

Thanks, Russ and good morning everyone. As usual, I will cover some of highlights of yesterday's new release then look at expense transit and discuss guidance. Looking first at the top line results. Q1 revenues from the sales of oil, condensate, natural gas and NGLs excluding hedging increased by 154% year-over-year to $38.8 million.

If you include the impact of $6.5 million loss on commodity derivate contracts revenues totaled $32.3 million. The increase in oil, condensate, natural gas and NGL's revenues is partially the result of 43% increase in production volumes from drilling activity in the Marcellus and Hunton plus the production we acquired in the Chesapeake acquisition in the second quarter last year and the WEHLU acquisition that closed mid-fourth quarter of 2013.

The production increases from these two acquisitions more than offset the loss of East Texas finds we sold early fourth quarter of 2013. Further 2013 first quarter production was negatively impacted by 2,800 Boe per day due to third-party pipeline issues in the Marcellus.

Before Hedging impact realized prices increase 78% resulting in an average realized price per Boe and $4.62 for the current quarter compared to $25.12 in the prior year period. A year-over-year increase and higher value liquids as a percentage of overall production continues to drive revenues higher.

Revenues from liquids were approximately 60% of our total production revenues in the first quarter this year compared to 50% a year ago and 65% for the fourth quarter, 2013. A slight sequential decline is result of 51% in increase in natural gas prices in first quarter 2014 compared to 13% increase in liquid prices during that same time period.

The $6.5 million on commodity derivatives contracts is a net impact that realized and unrealized hedging in the first quarter. this consisted of a realized loss on several hedged contracts of approximately $3.3 million and unrealized losses of approximately $3.2 million, which is called losses or gains related to the change in mark-to-market value for outstanding commodity derivate contracts in the 10-Q.

The impact to realized hedging losses decreased to reported Boe price by $3.86 or approximately 9%. First quarter 2013 realized hedging increased the price by $9.28 per Boe or approximately 37%. Even after accounting for the commodity derivative contracts that were settled during the quarter realized prices increase 19% to $40.76 per Boe versus $34.40 per Boe a year earlier.

Approximately 77% of our natural gas production, 62% of our oil and condensate and 91% of our NGL's productions were hedged last quarter. Like other in the E&P business that put hedges on and place two years, when prices were much lower. Our hedges are yielding losses in the near term. You can find complete details about our hedging program as of March 31 in our 10-Q filed yesterday.

Moving to the bottom line on adjusted basis, we have net income of $1.4 million or $0.02 a share compared with adjusted income of $6.1 million or $0.01 a year ago. Q1, 2014 adjustments include a $3.2 million mark-to-market loss as well as non-recurring charges of $235,000 primarily related to cost associated with parent company transition in Delaware and the merger of the old parent company in Gastar USA coupled with lagging cost related to last year's WEHLU acquisition.

In the prior year's first quarter, the adjustment included a $9.6 million mark-to-market loss and $1 million of litigation settlement expense. Similar to the prior quarter, Q1 bottom line results were most effective by higher DD&A, LOE and interest expense. All primarily related to the WEHLU acquisition which will I discuss more in a moment.

Q1 adjusted EBITDA was $25.9 million or $0.42 per diluted share versus $15.1 million or $0.24 a share a year ago. Adjusted cash flows from operations were $16.2 million or $0.26 per share versus $12.6 million or $0.20 per share a year ago. The detail of these non-GAAP financial matters were included in yesterday's press release.

Moving to production and please note that, since the majority of our revenue is now ride from liquids. We have converted from Mcfe to Boe for these discussions. Total average daily production was 9,700 Boe per day, which is at the top end of our guidance range. Q1 production was about 500 barrels a day was up about 500 barrels a day versus the fourth quarter and up 2,900 Boe per day from a year ago.

Mid-Continent production was up to 3,100 Boe per day from a year ago including our organic Hunton development and the impact to production acquired is part of Chesapeake in WEHLU acquisitions. Marcellus production was up 1,600 Boe per day year-over-year.

We were not impacted by any pipeline disruptions during the first quarter 2014 as compared to 2013 when third-party pipeline issues negatively impacted Marcellus production by approximately 2,800 Boe per day. These increases were partially offset by the impact of East Texas production sold in the fourth quarter last year that was producing an average of 1,800 Boe per day in the first quarter, 2013.

Of our combined Marcellus and Hunton first quarter, 2014 production about 59% was natural gas. Almost 23% was oil and 18% was NGLs. Again this quarter, while we are still waited to natural gas from a production standpoint, 60% of our revenues were weighted to liquids oil, condensate and NGL's.

We expect second quarter production assuming no additional outages in Marcellus or elsewhere to be lower than Q1 and be in a range of 8,400 Boe to 8,800 Boe per day. With just under 60% coming from the Marcellus. As we discussed in early April, our Marcellus production was temporarily curtailed by a rupture in the Williams pipeline that handles our Marshall County gas.

We estimate that, second quarter aggregated next production was reduced by about $162 million cubic feet of natural gas, 4,900 barrels of condensate and 8,000 barrels of NGL's as a result of the rupture, that's about 400 boe per day for the quarter and as impact is included in the second quarter guidance, I just described.

Currently our Marcellus production is not being impacted by the incident and we not expect any further negative impact from the pipeline rupture. Also contributing to the lower sequential guidance is a natural fields decline, the delay and the completion of the three Goudy wells are originally scheduled being in production in late May, 2014.

And lower than expected IP rates on recent Mid-Continent as previously discussed by Russ. We will expect to be on track with our full year guidance of 9,700 Boe to 11,000 Boe per day with our production growth continuing to be more heavily weighted, too late in the second half of the year.

We expect liquids production in the second quarter to be in the range of 42% to 44%. Pulling now the expense items, we delivered good performance on most of our expense lines coming in near the bottom of our guidance ranges.

Lease operating expense was $4 million or $4.56 per Boe which is at the bottom end of our guidance for Q1 compared with $1.8 million or $3.02 per Boe a year earlier and $3.3 million or $3.85 per Boe sequentially.

The sequential increase in LOE per Boe is due to a $0.25 per Boe increase in ad valorem taxes accrual and a $0.53 per Boe increase in well cost due to the full quarter impact for the WEHLU acquisition.

As we discussed last quarter, the WEHLU part of the acquisition resulted in higher overall cost associated with producing oil versus natural gas. The WEHLU acquisition posed in Mid-November last year.

Again although, first quarter LOE cost was a $1.63 higher Boe than a year ago revenue per Boe was $19.50 higher before hedging impact, which demonstrates the solid net benefit of growing oil production.

For the second quarter, we expect LOE to be in the range of $4.65 to $5.10 per Boe and reaffirm our full guidance of $4.55 to $5.10 range. Our DD&A rate per Boe in the first quarter of 2014 was $14.23 compared to $13.02 in the fourth quarter of 2013 and $8.83 in the first quarter, 2013.

The current quarter DD&A rates are pretty good indicator of the expense rate for the second quarter. Transportation, treating and gathering expense was $625,000 in Q1 or $0.72 per Boe, which is relatively flat versus the fourth quarter and at the low end of our first quarter guidance.

For the second quarter, we expect the expense range from $0.70 to $0.80 per Boe and $0.60 to $0.65 per Boe for the full year. Cash, G&A expense adjusted for corporate reorganization cost and acquisition cost was $3 million in the first quarter 2014 versus $2.9 million in the fourth quarter.

On a per Boe basis, first quarter adjusted G&A was $3.44 per Boe compared to a guidance of $3.40 to $3.70 per Boe. We expect second quarter cash G&A expense to range between $3.50 and $3.75 per Boe and reaffirm our full year guidance between to $2.90 and $3.20 per Boe.

Interest expense was $6.9 million in Q1, which is up $1.3 million sequentially and up $6.3 million from a year ago. You'll recall that we issued $200 million of 8 5/8 senior secured notes in May 2013 to fund the Chesapeake acquisition and an additional $125 million of 8 5/8 senior secured notes last November to finance a portion of the WEHLU acquisition.

We did not have any amounts drawn on our $120 million revolving credit facility as of March, 31 and as of this date continue to have no borrowings outstanding under the revolver. During the first quarter 2014, we sold $37,126,000 shares of Series A Preferred stock for net proceeds of $865,000.

Subsequent to quarter end, we issued an additional $49,714,000 Series A Preferred Shares for net proceeds of $1.2 million resulting a completion of our at the market issuance and currently total number of Series A Preferred shares outstanding is $4, 45,000.

Looking at CapEx we spent $35.3 million in Q1 versus $30.1 million in Q4, 2013 excluding acquisition cost. Currently, we still anticipate spending $192 million for the full year to price of $139 million for drilling and completion, $36 million for leasing cost, $8 million for infrastructure cost and $9 million for other capitalized cost.

We will continue to review our capital expenditure program throughout year and keep your apprised of any significant changes. Now I'll turn it back to Russ for final comments.

Russ Porter

Thank you, Mike. After our position with assets and two prolific basins. Each of which can individually provide substantial production, cash flow and reserve growth. Our Marcellus position is basically fully de-risk and we believe that the Utica-Point Pleasant potential can be rapidly de-risked on the basis of our activities along with those of other adjacent operators.

With more than third of our Mid-Continent acreage appears to be substantially de-risked in the Hunton Formation on the basis of the successful efforts with our joint venture AMI partner. Our upcoming lower Hunton drilling will provide valuable information on the remaining acreage.

The WEHLU property is upside potential and the form of the lower Hunton formation is currently underway with the drilling of the East and 22-1H well. Successful results from this well could have a significant impact on the value of that property since we currently have no proven reserves assigned to the lower Hunton on our WEHLU acreage.

The additional value contained in the stock play, the Woodford and the Meramec will be evaluated through join on the checkerboard assigned acreage the continuous success of other nearby operators in these formations and our own planned wells later this year.

We are almost in building a day and Gastar wasn't transformed overnight. So with a little patience and a diligent application of capital into these outstanding assets. I believe that we are poised to continue to deliver substantial value to all of our stakeholders in Gastar. That concludes our prepared remarks and this time, we will open it up for question-and-answers.

Question-and-Answer Session

(Operator Instructions) Our first question comes from Kim Pacanovsky – Imperial Capital.

Kim Pacanovsky – Imperial Capital, LLC

I have a question on your redirection of Hunton capital into the stacked play. Can you go through, what you had anticipated to drill as far as operated Hunton wells are this year and what you think, you might end up with and are we just looking at this two wells that you detailed as the only redirection of capital $10 million to $12 million for the Woodford well and I forgot what you said the Meramec well would cost.

Russ Porter

The Meramec cost about the same that is correct. We would anticipate originally I think 7 operated lower Hunton wells or we're redirecting just a portion of that capital to set these other formations. I'll tell you, it's not in any way a non-confidence support in the Hunton because we're very encouraged by the results we are seeing from the wells that are clinging up now and from the wells we just redid.

These other formations we think will have significant value. It's likely that they might have while slightly lower returns a little less variability then the Hunton has, so we want to get that understood as well as started de-risking this so we can demonstrate the value and hopefully get that added in on everyone's assessment of net asset value.

Kim Pacanovsky – Imperial Capital, LLC

And did you, exit your annual guidance number. Does that include success from this Woodford well and Meramec well, I think that it does?

Mike Gerlich

Kim, this is Mike. That is correct, as we reallocated that capital from the Hunton. We did make certain assumptions on the stacked play wells. I will mention to you that, really the Woodford that we stay on the schedule will really be the only kind of contributor to 2014 production that Meramec well will stand the schedule; we come in so late in the year. It really doesn’t have [indiscernible].

Kim Pacanovsky – Imperial Capital, LLC

Okay and just one more question on the Rosemary. I know that the Rosemary is fairly close to your Townsend and that's in the more fractured area and Rosemary if you look at the lateral length and also the percent oil. It looks to me like it can in even with 476 IP rate, it came in close to the tight curve, I think if you look at the percent oil and adjust for the lateral length.

So my question, what did you learn from that. I know that was on the guest or operated well. Any takeaways the relative success of that well as compared to Townsend?

Russ Porter

In the Townsend, we did have quite as many drilling problems as we had in the other wells. One of the issues we had with the Townsend was, we didn't get very good log. So we can evaluate the fractures as well, we can in the other wells. We get full data, where full active participant and all these non-op wells.

I think we understand pretty well, how to resolve the issues we had with the low circulation. So I think, the only way to judge is going forward on how we perform, but we have full information from that well. Huskey did a good job with it and the reason, why we don't think we can duplicate that.


Thank you. Our next question is from Gabriele Sorbara of Topeka Capital Markets. Please go ahead with your question.

Gabriele Sorbara – Topeka Capital Markets

Just trying to think about, looks like some of your wells are maybe gassier than AMI wells. I'm trying to think about the block up there. Is it, oiler and maybe your locations further south are going to gassier? How should we think about and are you more incline to target some of the gassier zones to get the uplift there or are you looking for more oilier zone?

Russ Porter

In general just as from a broad stroke, we think as you move further south. You do get a little bit gassier in the Hunton formation. As usual, we're doing a couple of things here. We are targeting our highest returns of course, but you were also exploring over an extremely large area. Up in the AMI we are drilling wells that are one and two mile step outs from successful wells.

Down here on our operated acreage, we're drilling out. We are stepping out 12 miles and 30 miles from the AMI and prospecting to learn the acreage find the sweet spots and then we will focus in around those. So we are not really focused on whether it's gassier or not, we are just focused on evaluating the potential and the asset as a whole.

Gabriele Sorbara – Topeka Capital Markets

Got it, okay and then just thinking about this fourth well. It looks like; the longest lateral that's been drilled. How should we think about maybe, are you doing anything different to ensure that this gets drilled and completed well without any issues, like you had in the third well.

Russ Porter

Yes, we just reached PBM in a well, this morning. We didn't have any issues at all, when we were drilling the lateral. As I stated, we saw strong shows. We drilled a vertical pilot through that well because we wanted to modern log information and the unit. We found porosity and upper middle and lower Hunton.

We are so far east and so far up yet, at this well location. If you actually do see some proceed development in the lower Hunton and not just the fractured development. So it will be interesting to see if we have porosity and fractures in the lower Hunton, but we drilled that well TD. We didn't have any issues, knock on a wood so far.

We should be logging it, I guess probably late tomorrow, early Saturday morning, we will case it and then we will mainly move over and drill a Bois d'Arc or upper Hunton well off to same pad. Now we saw very good shows in the upper Hunton, Bois d'Arc as we drilled through it for this well.

So we are feeling pretty good about that and also happy with operational performance.

Gabriele Sorbara – Topeka Capital Markets

Thanks and just a quick follow up here. Is the Huskey venture, the regular longer lateral has well going forward.

Russ Porter

No, I think their Hunton plans will remain consistent about 4,200-foot laterals in the Hunton.


Thank you. Our next question is from Neal Dingmann from SunTrust. Please go ahead with your question.

Neal Dingmann – SunTrust Robinson Humphrey, Inc.

Russ, I think I've asked this before, but just sort of follow-up on. Either Marcellus and then obviously with these Utica wells coming on. I know the prior problems you had with volumes, district spots obviously in light of what happened to Gulfport today. Your thoughts on takeaway that you have, in that Appalachian area?

Russ Porter

Neal, I'm guilty of not knowing what happened Gulfport today. So I've been, maybe I've been low internally focused, but if the questions regarding our takeaway capacity. Through the William system we have plenty of takeaway capacity for both wet and dry gas right now.

Their process and capacity is just over 0.5 Bcf a day growing to a 1 Bcf a day probably by sometime between June and October. So I don't foresee any fiscal constraints, unless getting gas out of the area. Now we are talking to Williams about a dry gas system for the Utica, so we wouldn't incur compression and processing charges and I think our activity along with stone and some other guys around us will probably just bought them converting the portion of their system to dry gas. Does that answer your question?

Neal Dingmann – SunTrust Robinson Humphrey, Inc.

It did, is that a big deal for them to convert that or the timing to convert that, Russ is that a big deal?

Russ Porter

You know, I'm not probably the most educated person to respond to that question. Mike McCown, you want to take a bite at that one?

Mike McCown

Currently, they're planning on landing the 24-inch pipeline to parallel their existing 12-inch pipeline and they've already started their construction effort. The plan is to make the 24-inch a wet gas line and convert the 12-inch line to dry gas that's their intention at this point.

Now so they will have adequate takeaway for both the Utica dry gas and the Marcellus wet gas. They want to do everything they can to bypass processing with the dry gas because they don't want to take up processing capacity with gas that doesn't need process. So they're working. We've got a great relationship with them and their run time is been excellent here. The last six months or so.

Neal Dingmann – SunTrust Robinson Humphrey, Inc.

Got it and then Russ, your thoughts. I guess there should be, the way you're looking at, as far as from a cost or in completion method from you know when you look at Marshall County versus Wetzel, did you anticipate much difference in those type of Utica wells?

Russ Porter

Well really doubt, now we think they should be very similar.

Neal Dingmann – SunTrust Robinson Humphrey, Inc.

Okay and then last, so just remind me. I forget, just on those well cost. What are you assuming for this well, are you just finishing and then. When you move over in the Wetzel?

Russ Porter

We've assumed for our first Utica well. The high-end of our cost estimate, which is $12 million and that would be the same for the, would be the assumption presently for the well we drilled in Wetzel County, but if we see a better result from that, then we will adjust our AFE on it.


Thank you. Our next question is from Don Crist of Johnson Rice. Please go ahead with your question.

Don Crist – Johnson Rice & Company

Sticking into Marcellus for now, at the Analyst Day I talked about the acreage swaps and possibly executing a few more, have any more of those gotten done and increased your net acreage or net locations in the area?

Russ Porter

We've done a couple other small slobs, but they've just been to firm up our positions in the well count we already gave, so there hasn't been any more than, actually add rose or net wells.

Don Crist – Johnson Rice & Company

Okay and cycling over towards the Hunton area. Can you remind us of the production mix of the Woodford and or what you except the production mix of the Woodford and Meramec wells to be on your acreage?

Russ Porter

Well, based on what we've seen from the data we've got from some surrounding. The Woodford is gassier, probably 65% gas, 35%-40% liquids, but the Meramec is oilier in summer to the Hunton.

Don Crist – Johnson Rice & Company

Okay, that's all I've got. Everything else has been asked. Thanks.


Thank you. (Operator Instructions). Our next question is from Jason Wangler of Wunderlich Securities. Please go ahead with your question.

Jason Wangler – Wunderlich Securities

Just curios, up in the Marcellus and you know last question obviously about trading acreage but also is there much left or way to pick up or is it pretty much all leased. I'm just curious, as far as you start looking in this Utica play, as you're starting to starting to kill these wells.

Russ Porter

The whole area is pretty well leased up. I mean, the ultra-rich portion of the Marcellus, always attractive before the Utica became apparent as another target. So there is really very, very little open acreage.

Jason Wangler – Wunderlich Securities

And then just obviously you didn't expand in Oklahoma as far as kind of shifting the CapEx budget according to kind of some things that you're seeing, is that something that could you maybe do up in the Marcellus and Utica as we get more data from player from yourself and from others?

Russ Porter

Yes, it definitely is and there is some strategic advantage to it or some synergies or whatever you'd like to call it because the Marcellus is so de-risk and so well understood and as well drill Utica wells and logged the Marcellus. We can actually book proved and developed Marcellus reserves on the basis on the Utica log or log drilled for Utica well.

So if we divert some capital from the Marcellus program to the Utica. We are de-risking the Utica. We are adding that value in to the company, we are getting that production but we are also adding proved and developed reserves in the Marcellus.

So yes, it's sort of almost two for one type deal as we divert that capital to the Utica.


Thank you. There are no further questions, Mr. Porter. I'll turn it back to you for closing remarks.

Russ Porter

Okay, as usual. Thank you everyone for your time and catching up on Gastar and if you have any additional questions or follow-up. You can feel free to try to reach Mike Gerlich or myself here in the office. Thank you.


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