Gastar Exploration's (GST) CEO Russell Porter on Q2 2014 Results - Earnings Call Transcript

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Gastar Exploration (NYSEMKT:GST)

Q2 2014 Earnings Call

August 08, 2014 11:00 am ET

Executives

Lisa Elliott - Principal

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

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

Michael McCown - Chief Operating Officer and Senior Vice President

Analysts

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

Kim M. Pacanovsky - Imperial Capital, LLC, Research Division

Jason A. Wangler - Wunderlich Securities Inc., Research Division

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

Gabriele Sorbara - Topeka Capital Markets Inc., Research Division

Brad Pattarozzi - Heikkinen Energy Advisors, LLC

Chad L. Mabry - MLV & Co LLC, Research Division

Jamaal Dardar - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

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

David E. Beard - Iberia Capital Partners, Research Division

Operator

Good morning, and thank you for standing by. Welcome to the Gastar Exploration's Second Quarter 2014 Earnings Call. [Operator Instructions] As a reminder, this conference is being recorded today, on August 8, 2014. I would now like to turn the call over to Lisa Elliott of Dennard-Lascar. Please go, ahead.

Lisa Elliott

Thank you, Lorli, and good morning, everyone. As a reminder, today's call will contain forward-looking statements, and 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 Form 10-K from 2013, filed on March 13, 2014 and subsequent SEC filings, which can also be found on 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, August 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 the replay information in yesterday's news release.

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

J. Russell Porter

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

I'd like to start with a recap of our midyear reserve update, which demonstrated significant value creation in the first half of the year in both our Mid-Continent and Appalachian plays.

At June 30, 2014, we realized a 43% increase in proved reserves over December 31, 2013. Our proved reserves at midyear totaled 78 million barrels of oil equivalent with the ratio of oil and liquids up slightly to 46%. The PV-10 value at SEC pricing increased 39% to $826 million. If you use a July 1, 2014, NYMEX forward curve pricing, the PV-10 values is $805 million.

Marcellus reserves in the Appalachian basin represented 71% of proved reserve volumes and 51% of the SEC PV-10 value while Hunton Limestone reserves in Oklahoma represented 29% of proved reserve volumes and 49% of the SEC PV-10 value.

With nearly half of our total SEC PV-10 reserve value derived from our oil-focused assets in the Hunton, the benefit from the continued strength in oil prices is clearly demonstrated. Proved undeveloped or PUD reserves at midyear 2014 represented approximately 62% of the total proved reserves compared to approximately 44% at year-end 2013. The total PUDs has a SEC PV-10 value of $451 million. The Appalachian basin represented 56% and Oklahoma represented 44% of the PUD value.

We have booked 72 gross Marcellus PUD locations, up from 40 gross at December 31 and 96 Hunton PUD locations up from 73 gross at year-end. We're very well-positioned to realize additional reserves and production from our current development program, as well as from a robust exploration program that is in progress. Numerous important tests are currently underway or planned for the very near-term, which could have a very meaningfully impact on our net asset value. As we've discussed in the past, we're evaluating the prospectivity of several previously untested formations, including the Utica-Point Pleasant shale on our Appalachian acreage and the Woodford and Meramec, Mississippi lime shales or Stack play on our Oklahoma acreage. Obviously, depending upon what we find, we can substantially increase our drilling inventory and resource potential, as well as expand our development options. We should have the opportunity to prove up multiple formations with a single well bore and leverage our drilling and lease costs, as well as hold acreage by production with 1 formation for future development of another. Based on the results of other operators near our acreage and initial data we've obtained from our activity, we believe that the Utica-Point Pleasant formation underlies all of our Marcellus West acreage and the Stack play could be present across a broad portion of our acreage in the mid-continent. In addition to progressing our Marcellus and Hunton development programs, we believe our exploration program focused on these formations can generate substantial near-term shareholder value in the form of reserve additions and increased drilling inventory. Along with the potential to add Utica-Point Pleasant reserves this year, we are also excited about our potential to further increase a number of Hunton and Marcellus PUDs at year-end 2014. We are working to prove up our producing formations on unexplored portions of our acreage. Currently, those efforts are underway with Lower Hunton test in our WEHLU acreage and soon with Utica and Marcellus tests in Wetzel County, West Virginia. We're closely monitoring the Easton 22-1H well in Oklahoma, our first is of the Lower Hunton oil formation on our WEHLU acreage, which we acquired in November of '13. Although the potential impact of the well in our oil reserves and drilling inventory might be a little less obvious, we think it's meaningful as its success is the first step in significantly derisking the Lower Hunton formation on a portion of our 24,000-acre WEHLU unit and should allow us to start booking additional proved undeveloped oil reserves. We completed this well in late July and after less than 2 weeks of being on flowback operations and the recovery of less than 2% of the completion fluids, the wells most recent 5-day average production rate is 460 Boe per day, of which 88% is oil.

This compares very favorably to our better performing Hunton wells elsewhere on our acreage. To illustrate the value potential of this well and beginning to derisk the play, the 44 Lower Hunton probable locations covering only 7,000 of our 24,000 acre net unit have a PV-10 value of $132 million assuming SEC pricing and assuming that each well meets our EUR of 250,000 barrels of oil equivalent type curve. Although it's early, our first Lower Hunton well looks to be outperforming that type curve. If you recall, we paid $178 million for the WEHLU property, so the addition of $132 million in incremental future proved value could make the economics of this acquisition even more attractive. In addition, we just completed our first Upper Hunton well, the Easton 22-2H on the WEHLU acreage. Earlier results from the flowback of the Easton 22-2H well is also encouraging as the well is currently producing at a rate of 224 Boe per day, 93% oil, after just 2 days on flowback. Again, this compares very favorably with our best wells in the play. If this well's production performance also exceeds our internal type curve of 125,000 Boe, it could result in an additional incremental proved reserves from the 61 PUD locations booked on only 7,000 net acres. In Appalachia, based on the initial data we have from our first Utica-Point Pleasant test, the Sims [ph] U5H we're confident we'll be adding proved reserve from that well. As we previously announced, logs showed that we encountered 92 feet the high porosity pay, which has responded well to fracture stimulation. We frac-ed 25 stages over the 4,200-foot lateral and are currently allowing the well to soak or rest for approximately 3 weeks. We should commence flowback operations in late August, and we have ample capacity in the midstream system for Utica volumes.

Our next Utica-Point Pleasant well is currently planned in Marshall County on the Blake pad. Drilling operations in the Blake pads should start by early October. We plan to drill 2 Marcellus wells and 1 Utica well. Depending on permit timing, we anticipate commencing our first Marcellus and Utica-Point Pleasant wells in Wetzel County, West Virginia, by early 2015.

Based on the results from offset operators, we believe that the Marcellus and the Utica-Point Pleasant formation in Wetzel County should be as productive as it is on Marshall County. If we successfully confirmed that the Utica-Point Pleasant formation is present and commercially productive on our acreage, we could have approximately 118 gross Utica drilling locations in Marshall, Wetzel counties assuming 1,000-foot spacing between laterals.

In addition, when we confirmed that the Marcellus is productive in Wetzel County, we will significantly derisk 96 gross Marcellus, Wetzel county drilling locations. Given the success of other operators in Wetzel County, we firmly believe that the Marcellus and the Utica-Point Pleasant could be successfully developed on our Wetzel County acreage. In the Mid-Continent, the Stack play offers potential to test more than 1 formation with a well or hold production from 1 formation and later develop another. Currently, nonoperated Stack play tests are underway or planned for the second half of 2014 and early 2015. We've been very encouraged by the positive results and the high-level of activity on nearby acreage from operators like Newfield and Devon to derisk these plays. Our Woodford test is underway by a third party of 9600 gross acres that we farmed out on a checkerboard basis earlier this year. As you may recall, we retained every other section, and we'll benefit from the valuable cost free well data. It should help us better understand the Stack play potential in this area.

Based on their drilling results, we may even able to add booked proven undeveloped reserves on our offsetting acreage without drilling a well. We're closely monitoring Newfield success identifying and developing the Stack play on acreage that is adjacent to our leasehold.

We're still waiting on the completion of a Canadian County Woodford Shale well, originally drilled by QEP in which we have a small working interest. That well is now owned by Summilux [ph]. We expect it to be completed by year end.

We believe that we have approximately 24,000 net acres prospective for the Woodford Shale that can come -- that can accommodate approximately 200 net wells. We also believe that the Meramec could be perspective on 60,000 net acres within our mid-continent lease hold and we can have approximately 300 net Meramec well locations.

Our first operated Stack play well is now scheduled for the second quarter of 2015 in Kingfisher County.

Before I turn it over to Mike, I'll go -- give you a quick update on our current Marcellus and Hunton drilling activity. In Marshall County West Virginia, with our SIMMS U-5H Utica-Point Pleasant well now completed, we've commenced horizontal drilling on the 7-well Armstrong pad. We'll then move over to the Hansen pad to begin horizontal drilling operations on 3 wells there. The Armstrong pad should be in production in November of 2014 followed by the Hansen pad in December.

On our operated acreage outside of our AMI and the mid-continent Hunton oil play, we've drilled the Horseshoe 3-1H lower Hunton well in Canadian County, Oklahoma, to total depth. The Horseshoe 3-1H is expected to commence flowback operations in the first half of September. To date, our drilling time and cost have improved considerably compared to our first 3 operated wells. Operations within our AMI acreage have been very active with 4 rigs running. We've been pleased with the overall results and periodically we post a schedule on our website of production results and drilling activity. We updated production yesterday on those wells. You're welcome to sign up to receive alerts when we update that report by going to the Investor Relations section of our website.

I'll now turn it over to Mike for an update on our financials for the quarter.

Michael A. Gerlich

Thanks, Russ, and good morning, everyone. As usual, I will cover some of the highlights of yesterday's news release, then look at expense trends and discuss guidance. Before I begin, our current quarter results include the impact of a net bottom line benefit of $8.6 million, related to a confidential arbitration contract settlement. The confidentiality provisions of the settlement prohibit us from sharing many details, but the settlement related to our West Virginia operated wells it was comprised of a $10.6 million increase in revenues coupled with related recognition of $584,000 in production taxes, $185,000 lease operating expense benefit, and an increase in treating transportation and marketing expense of $1.6 million.

Approximately $1.5 million of the net settlement relates to the current year. Because the settlement represented price or expense adjustments based on volumes previously sold, the settlement is included within each applicable income statement line item. The only another thing that I can share is that although there were some changes to the contracts, the settlement did not result in an increase in any existing contract fees or have any impact on reported production volumes.

Now beginning with top line results. Revenues from sales of oil condensate, NGLs and natural gas, excluding the effective hedging, increased by 88% from a year ago to $44.8 million. If you exclude the arbitration settlement revenue adjustment, revenues increased 43%, primarily due to a 45% increase in average Boe pricing partially offset by a 1% decrease in production. Excluding the arbitration settlement, our pre-hedge Boe price in the current quarter was $39.72 compared to $27.36 in the prior year. Higher oil revenues contributed to the majority of the revenue improvement over prior year quarter as natural gas and NGLs prices were only slightly higher. The increase in production mix towards higher value liquids, particularly from drilling oil production from the mid-continent continues to increase revenues and average pricing per Boe.

Revenues from liquids, as a percentage of production revenues, remain constant quarter-to-quarter at approximately 60% of our total production revenues, compared to 48% a year ago. Excluding the arbitration settlement, liquids represented about 72% of current quarter production revenues. Looking at quarterly product prices sequentially and excluding the arbitration settlement and realized hedging, natural gas and NGL pricing declined 30% and 37%, respectively, while oil prices increased 12%.

As others have reported, our West Virginia natural gas production was impacted by the natural gas basis differential decline during the second quarter of 2014.

In the first quarter of 2014, our West Virginia gas differential in the first month prices was a negative $0.22 while current second quarter basis differential widened to a negative $0.92.

As a reminder, our natural gas is priced based on TETCO M2. This basis point historically has been less volatile than certain basis points in the region. Unfortunately, the basis differential has continued to expand post-quarter-end. Based on current future price projections the TETCO M2 is projected to be negative by about $1.52 for the remainder of 2014.

We have recently added approximately 5,000 per day of West Virginia basis hedges at an average negative price of $1.36 for the remainder of 2014 and negative $1.12 for 2015. We will continue to monitor the basis differential in the area, and we will look at adding additional hedges or other means of managing the basis differential risk.

Sequentially, NGL pricing, as a percent of WTI average posted price, declined from an average of 45% from the first quarter this year to 27% in the current quarter or $26.88 per barrel as compared to $26.17 per barrel for the second quarter of 2013. We currently have NGL hedges for 500 barrels per day at an average price of $47.10. The 1% production decline in Q2 which is actually less than what -- than we have previously forecasted was in part the result of previously announced third-party pipeline rupturing in early April that shut-in our Marcellus production for 4.5 days, coupled with natural declines in the Marcellus. Just as a point of reference, we have not placed on production any new Marcellus wells since August of last year when we ceased development in order to work out the remaining midstream operational problems. To accommodate safe drilling and completion operations on their respective pads, 4 producing Goudy Marcellus wells and 3 SIMMS Marcellus well were shut-in, in April. The 4 shut-in Goudy wells were placed back on production in July and the 3 shut-in SIMM wells are expected to be back on production by mid-August. With the completion of frac-ing operations on the SIMMS U5H. Looking at hedging, we recognize an $8.9 million loss of commodity derivative contracts comprised of a realized loss on settled hedged contracts of approximately $3.5 million, and an unrealized hedging loss of approximately $5.4 million related to the change in mark-to-market value for outstanding commodity derivative contracts.

Again, excluding the benefit of the arbitration settlement, the impact to realized hedging losses decreased the reported Boe price by $4.05 or 10%. In the same period, last year, realized hedging decreased the price per Boe by $0.51 or 2%. After accounting for the commodity derivative contracts that were settled during the second quarter, realized prices still improved to $35.67 per Boe, excluding the benefit of the arbitration settlement, versus $26.85 per Boe, a year earlier. This is, again, reflective of our ever-growing oil production. Approximately 99% of our natural gas production, 60% of our oil and condensate production, and 82% of our NGLs production were hedged in the second quarter. You can find complete details of all our hedging program as of June 30 in our 10-Q filed yesterday.

Moving to the bottom line. On an adjusted basis, excluding the $5.4 million mark-to-market loss and including the net benefit of $8.6 million related to the arbitration settlement, we had net income of $7.5 million or $0.12 per diluted share in the latest quarter. Excluding the mark-to-market hedging and the arbitration settlement gain, we had a current quarter loss of $1.2 million or $0.02 per share. That compares with adjusted net income of $3.4 million or a nickel a share a year earlier, excluding mark-to-market gain, and a large gain on the acquisition of assets in Oklahoma and related cost.

Current quarter adjusted EBITDA was $29.4 million, a $0.47 per diluted share versus $16.8 million or $0.26 a share a year ago. Adjusted cash flow from operations were $19.7 million or $0.32 per share versus $12.8 million or $0.20 per share a year ago. Excluding the arbitration gain, current adjusted quarter EBITDA and cash flow was $20.8 million and $11.1 million respectively. The detail on these non-GAAP financial measures was included in yesterday's news release.

Moving to production. Total average daily production was 9,500 Boe per day, which is 8% above the top end of our guidance range of 8,400 to 8,800 Boe per day. Marcellus production was about 5,400 Boe per day, which is about -- down about 1,000 Boe per day from first quarter 2014 and down 2,000 Boe per day from a year ago. The April 2014 pipeline rupture accounted for about 400 Boe per day of decline and the remainder a result of shutting in 7 Goudy and SIMM wells that I discussed earlier in natural declines in production from existing wells. Mid-Continent production increased by 800 Boe per day sequentially, reflecting the success of our development program and has increased by 3,500 Boe per day from a year ago, which primarily reflects the impact of the Chesapeake and WEHLU acquisitions. 45% of our mid-continent current quarter production was oil and 27% was NGLs.

Our Oklahoma oil-only production in the current quarter averaged 1,830 barrels of oil per day as compared to 380 in the second quarter of last year.

Looking at total company production by product for the current quarter, 24% was oil and condensate, 24% NGLs, and 52% was natural gas. Assuming no production curtailments, we expect Q3 production to be in the range of 9,500 to 9,900 Boe per day, with 45% coming from Oklahoma and 55% coming from the Marcellus. The liquids percentage should be in the range of 44% to 47% of production. Regarding production guidance, we are tightening our full year guidance to 10,200 to 10,600 Boe per day from the 9,700 to 11,000 Boe per day, of which liquids percentage will now range from 45% to 48%, up from the prior midpoint guidance of 42%.

Since our capital cost we weighted to the second half of the year, we are looking at a strong December exit rate. Currently, we anticipate that our December production will average between 13,200 and 13,800 Boe per day, of which liquids percentage is expected to range from 47% to 50%. The production ramp-up is supported by looking at the timing of new wells being placed on production. Through June 30, we placed on production only 9 gross Hunton wells and no wells in the Marcellus. During the second half of the year, we are projected to add 25 additional gross Hunton wells, 10 gross Marcellus wells, and 1 gross Utica well. The Hunton wells are added almost equally by quarter in the second half while all 10 Marcellus wells will be added in the fourth quarter. The Utica well should be on production by early September.

Turning now to expense items. Our lease operating expense per Boe was higher than our guidance due to about 350,000 or $0.41 per Boe related to unplanned workover expenses to remove scale from wells in the Marcellus along with the electric submersible pump or ESP repairs in Oklahoma and higher costs associated to the increase in liquids production.

Total LOE was 4.9 million, including the benefit of a onetime reduction related to the arbitration settlement of 185,000, versus 2.2 million a year ago, and 4 million in the first quarter.

On a Boe basis, that's $5.88, excluding the onetime benefit, as compared to a guidance of $4.65 to $5.10, $2.48 a year ago and $4.65 per Boe in the first quarter.

For the third quarter, we expect LOE to be in the range of $5.25 to $5.50 per Boe and updated full year guidance is $5 to $5.30 per Boe. The decline in Boe rate from current levels are reflective of anticipated production increases.

Our DD&A rate per Boe in the second quarter was $11.94 compared with $14.23 in the first quarter and $8.70 a year ago. The decline in the sequential quarter DD&A rate was a result of the 43% increase in proved reserves.

Transportation treating gathering expense in Q2, excluding the impact of the arbitration settlement adjustment was $0.65 per Boe in the second quarter versus $1.29 per Boe last year, and $0.72 per Boe in the first quarter of this year.

For the third quarter, we expect treating transportation gathering expense to be in a range of $0.60 to $0.70 per Boe and a full range to -- year range to be in that same value. Cash G&A expense was $2.9 million in the second quarter versus $3.2 million in the first quarter of 2014. On a per Boe basis, second quarter cash G&A was $3.36 per Boe, which is more than a dime below the low end of our guidance. For the third quarter, we expect cash G&A expense to be in the range of $3.20 to $3.35 for both Boe, and full year cash G&A to be in the range of $3 to $3.30 per Boe.

During the second quarter, we drew $20 million on our $120 million revolving credit facility to fund capital activity. We are anticipating the revolver borrowing base will be increased by $25 million to $145 million before the end of the month. The borrowing increase is the result of the midyear reserves increase. We continue to use our revolver as a source of liquidity to fund our capital activities and anticipate continued future growth in the borrowing base. Looking at capital expenditures. Year-to-date, we've spent $73 million comprised of $37 million in the second quarter and $36 million in the first quarter.

We are increasing our 2014 capital expenditures budget by $32 million to $224 million. The higher budget allocates an additional $19 million to the mid-continent, $17 million for Appalachia along with a decrease of $4 million at other capitalized costs. The mid-continent increase is necessary primarily to fund the drilling of 10 gross, 5.3 net additional Hunton wells within the AMI area and 3 gross 2.9 net operated wells within WEHLU.

We are also budgeting for an additional 4 gross, 2 net Marcellus pad wells and 1 gross 0.5 net Utica well for $17 million plus related infrastructure and land cost. This should result in total 2014 gross wells drilled of 36 in the Hunton, 14 in the Marcellus, and 2 in the Utica-Point Pleasant. The strong drilling success we've realized in both areas this year, is the driver for these capital additions. Again, because we are spending the majority of our capital late in the year, our 2014 production guidance has not increased much beyond our original guidance midpoint, but as we discussed, these expenditures yield a very strong production exit rate in December and even stronger 2015 production. Now I'll turn it back to Russ for final comments.

J. Russell Porter

Okay. Thank you, Mike. As we outlined, our current exploration activities position us to continue to grow our reserves, more fully evaluate the potential of our asset base and increase the net asset value of the company. As our development programs become more active in the second half of the year, we expect to see our production growth building again as we bring online newly completed Marcellus, and Utica-Point Pleasant wells, and Marshall County and maintaining an active drilling and completion program in Oklahoma.

Thus far, we're very pleased with the initial results of this exploration efforts. The SIMMS U-5H Utica-Point Pleasant well logs in response to the 25-stage fractures stimulation seems to confirm our expectations with regard to potential deliverability and resource potential. Additionally, the early production performance of our Easton 22-1H, Lower Hunton test, and 22H Upper Hunton test are very encouraging.

With several non-operated Stack play tests being drilled in the second half of this year on or adjacent or acreage we'll be in the much better position to determine our next steps in the Stack play by year-end. And then early next year, we'll initiate operator test in the Stack play. Finally, as we announced this morning, we're very pleased to welcome 2 new independent directors to Gastar's board. Steve Holditch and Jerry Schuyler brings a combination of technical, operational, and management experience and wisdom that we look forward to tapping into as we continue to grow Gastar through the exploitation of our existing assets. We've had an active and successful first half of the year. We're looking forward to update you the results of the second half. I'm very optimistic we'll continue to have good news to report. That concludes our prepared remarks. And operator, we're ready to take questions at this time.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question is from Ron Mills of Johnson Rice.

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

On the Utica well, you got the frac put away. Any other commentary around how the frac went? What kind of treating pressures you saw? A lot of positive commentary this morning from another operator and a larger one earlier this week. Just trying to see if there's more color there. And I know it's drilled from an existing pad, but is the gathering system everything in place capable of handling the higher rates that could be associated with the Utica?

J. Russell Porter

Yes, I'll answer the last part of your question first and then I'll let Mike McCown answer question regarding how the well responded to treatment. We have ample capacity in our midstream system for our early Utica wells. We're working with Williams to possibly get a dedicated dry gas line in place so we would not have to put the Utica gas through a wet gas system and have to pay some compression and processing that's really not necessarily. So there really are no near-term midstream bottlenecks as regards to testing and derisking the Utica. Mike McCown, I'll let you respond to Ron's question about how the well responded to the fracture and the pressures we saw.

Michael McCown

Yes, Ron, well treated well. The treating pressures were high. We anticipated them because the depth and the higher pressure of the formation in this area but we were able to please all the sand in 23 of the 25 stages we put approaching 450,000 pounds of sand into each stage. So it treated as designed, and again the high pressures, and the high shut-in pressures are very encouraging. We've seen nothing to dissuade us from the well coming as we anticipated. And we're in the process now of returning the 3 existing Marcellus wells to production while we let this well rest. At the end of the month we'll be flow testing it and having it ready for sales by the 1st of September.

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

Is the resting period something that you think will remain, that people will continue doing on the gas side?

Michael McCown

Well, that's a good question. We're evaluating that ourselves. And as you know, this is the first well that we've drilled. And since most of the offset operators are doing that, we're following suit. So whether it's necessary or not, it's necessary in our case because we've got these other wells that we need to return to production, but we're trying to evaluate that and determine how much of a resting period is necessary and that varies from operator to operator. So short answer is, I don't know at this time, Ron.

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

Okay, great. And then second question on the Hunton. You talk about the WEHLU and both the upper versus the lower, but first you talked about the $130 million of PV-10 associated with those probables. Can you talk about how much of that 24,000 acres you thinking could be derisked by this well i.e. is there up dip, down dip wells? And how do you think from working with your reserve engineers in the past, they will approach that?

J. Russell Porter

Sure, Ron, there's a couple of things there. The 44 probable locations that we booked in the Lower Hunton cover about 7,000 of the 24,000 net acres. And that 7,000 acres is really limited to the north half of the field. We think the southern half is just as perspective and we'll be testing that, later this year with our initial vertical pilot well there and probably a couple of horizontals as well. The thing that we saw as we drilled this well and completed it, we gathered some micro seismic data. It looks like you're getting longer frac halflinks than what we expected, it's an early indication that we may be able to drain larger areas than we originally had planned. So we may be looking at a lower number of well bores needed to recover the same amount of reserves, which would have a very positive impact on value. So when you look at this acquisition being made less than a year ago and the ability to add this sort of value within the first year of owning this property, it's really working out, as well as we probably could've hoped.

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

Okay, great. And then, Mike, I apologize for going over. But Mike, the exit rate average that you threw out in the 13,000 Boe per day -- or 13,000 to 14,000. Is that the exit? Or did you say that, that was the December average?

Michael A. Gerlich

That is the December average.

Operator

Our next question comes from Kim Pacanovsky of Imperial Capital.

Kim M. Pacanovsky - Imperial Capital, LLC, Research Division

I'm just -- just to tag onto Ron's question or your answer rather about the fracturing. Did you see any of those wider open fractures that you've seeing in your operated acreage in the north? These wells got completed quickly, it seems without a hitch. So if you could just let us know what you saw on the fracturing there? And also if you did anything different in the completions?

J. Russell Porter

What we saw, these wells are drilled in a very up dip position and what we found was that in the Lower Hunton, we have not only the natural fracturing but we also had some matrix porosity. We also -- we evaluated this with a vertical pilot hole prior to drilling the horizontals. We also found very good porosity development in the Middle Hunton, which we think we've accessed with our completion, as well as the Upper Hunton, which we, of course, we accessed with a different well bore. We designed these completions as combination of taking advantage of that porosity as well as the natural fractures. So it's a bit of a hybrid completion compared to what we're doing elsewhere in the acreage but we basically just evaluate what the rock tells us and design our completions around each one. We don't really have a cookie cutter system. We're looking at each well and designing this completion on our per well basis.

Kim M. Pacanovsky - Imperial Capital, LLC, Research Division

Okay, great. And the second question is could you just go through your lease -- how much of the acreage is HBP and WEHLU? And are you facing any issues with lease expirations, especially in the that southern part of the acreage where you won't get to until the end of the year?

J. Russell Porter

I mean, you've got to remember WEHLU is a unit and it's 24,000 acres that's all held by production. If we're down to a single economic well, we'll hold that entire unit.

Operator

Our next question is from Jason Wangler from Wunderlich Securities.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Curious, Russ, as far as with how the drilling went on in the first Utica, the plans as you go to the second one in a couple of months. You're looking at the same type of frac stages, laterals things like that, are your learning a little bit as you can go down the path?

J. Russell Porter

Yes, we learned quite a bit. We drilled this first Utica well on a liquid mud system, which will change going forward. We'll drill most of the well on air and switch over to on oil base system. After we set intermediate, that would save us a lot of time, as well as expense. Our laterals going forward we're trying to design those to be as long as possible. This first well only had a 4200-foot lateral. That was a combination of several factors but as we go forward, most of our laterals will probably be in the 5,000 to 6,000-foot range with as close to 6,000 as we can get. As far as the number of frac stages, we wanted to be somewhat aggressive on the completion of this well. I think that number stages over that length of horizontal is probably on par of what we'll do going forward.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Okay. That's great. And then maybe over to Oklahoma, you kind of touched on that I think, from Ron's question a bit. You had some of the issues with those first operated wells it's just kind of a different -- the larger fracs, I mean, as you start to look not only in WEHLU because outside of that, is it still kind of drilling as quiet as possible? Or where are the changes that you guys are looking at as you kind of really ramp up the program in the second half?

J. Russell Porter

We just drilled that Horseshoe well with really no problems at all in the lateral, no lost circulation. We just got the log on it. We were very encouraged about what we see with the first cut at looking at the log. So I think we're coming down the learning curve fairly quickly there. It's -- there really weren't any issues that we didn't think that we couldn't resolve. And thankfully it looks like we resolved most of them. We did not hit any of the unusually large open fractures like we did on the Taborek well that caused us some issues. Part of it also is our G&G team is really honing in on exactly where they want to land these wells and landing it and keeping it in the zone. So as we learn, which portions of the formation give us a lot fewer drilling problems and the we will be able to target our well bore to that particular part of the formation.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Great, and that's great to hear. Just and then one other one just on the CapEx. Obviously you've been ramping and obviously the spending's going to be higher in the second half. Just will that be pretty much distributed pretty evenly across the 2 quarters? Or is it kind of continue to ramp kind of as productions are looking to ramp throughout the next 6 months, just kind of getting an idea on the spend?

Michael A. Gerlich

It will be -- this is Mike. It will be slightly weighted little heavier to the fourth quarter, but not that much difference. We're pretty active right now with the operated rig in Hunton. Obviously, we have 4 rigs with our partner in the AMI and we've got a shallow rig and a deep rig working in West Virginia. So it will be fairly laid out, but a slight heavier in the fourth quarter just because the way the completions are timed.

Operator

Our next question is from Joel Musante from Euro Pacific Capital.

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

On the Utica, do you -- does the production from the Marcellus hold the deep rights?

J. Russell Porter

On most of our acreage, it does. There's a few leases that we're working on where we didn't have the deeper rights, but we are very close to getting all of those wrapped up.

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

Okay. And on the first well there, the SIMMS well, are you planning to do and kind of a pressure maintenance program on that? I know that you're mentioned success.

J. Russell Porter

Yes, we're talking about that internally. Yes, I think there is probably some validity to holding back pressure on these wells and not producing them at the highest rates possible. I think that our plan on this well is initially to hold back pressure on the well, produce it on a restricted basis for several months and then see what the well tells us and see how long we could hold it flat at whatever rate we choose and then start opening it up to see what it does from there. But yes, that will be a learn as we go type of exercise.

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

Okay, all right. And just on your pricing, it looks like your differentials are moving around a little bit. Is there, I mean, can you give me some guidance on percent oil, percent gas, percent NGLs from the benchmark?

Michael A. Gerlich

Oh sure. I can say that to you. Just give me a second and I'll pull it up. But it's -- we talked about -- we saw a real change in our pricing between quarters. I mean, if you look at our oil compared to WTI total company in the second quarter, we got 92%. We continue to get a premium in our Mid-Continent area, where we basically get 102% to 103% of the WTI posted price. Even in on our Marcellus, if you look at Q1 to Q2, Q1 where we got about 54% of a WTI and in Q2, we got 52%. Looking at gas, obviously, we talked about the differential impact, but for the quarter, total company wise, we got about 77% of an average Henry Hub price. That breaks out to Mid-Continent getting about 84% and the Marcellus 75%. That was down from the first quarter where because of the winter months, company wise, we were 99% of Henry Hub. Got a premium in the Mid-Continent of 112% and we were 95% in the Marcellus. The other real change was for the NGLs, okay? That's where if you again compare back to WTI, first quarter we were 45%, this quarter 26%. We saw both areas decline, I mean if you looked at our Mid-Continent, we were about 34% of WTI. We were only 17% of the Marcellus, obviously, down pretty significantly from first quarter. We have seen some improvement on the NGLs side. The gas differential I talked to about that previously, we've seen that further deteriorate.

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

So, just going forward, do you think it's going to be more like the first quarter? Or the second quarter?

Michael A. Gerlich

Well, I would think that this point going in the third quarter, it's more or likely to be like the second quarter.

J. Russell Porter

The second quarter or a little worse

Michael A. Gerlich

On the Marcellus side of this, it's going to be down some more. Then hopefully as we get back into the fourth quarter and winter comes around, those prices will improve some.

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

Okay, all right. And just one last one. I guess you're looking at possible divestitures, I don't know if you -- I'm just wondering what that might look like on a Stack pay asset portfolio?

J. Russell Porter

We're not looking at any possible divestitures right now. That's not even a part of our plan.

Operator

Our next question is from Gabriele Sorbara from Topeka Capital Markets.

Gabriele Sorbara - Topeka Capital Markets Inc., Research Division

It looks like Cimarex had a good Meramec well further west in Canadian County. I'm just wondering if you guys can comment on maybe how the geology changes as you move further east towards your block? Obviously, the QEP well's been drilled Cimarex will complete that. They must be encouraged there. Do you have any color also maybe how that log looks? And anything you could share on that would be helpful.

J. Russell Porter

I don't have any color on the log because if I've seen it I don't remember, to be brutally honest with you. As far as the geology, we think that if you look at the Meramec potential, most of that on our acreage starts just north of the Kingfisher County line and really encompasses essentially everything we've got in Kingfisher County. And that's based on the mapping we've done on thickness in the Meramec. We see about 300 net locations there on about, I think, 60,000 acres that's perspective of our net acres, I should say. The Meramec seems to be pretty consistent. You do have thinning and thickening and we think the ample thickness occurs that acreage is what sets us up for development.

Gabriele Sorbara - Topeka Capital Markets Inc., Research Division

So when we think about the 60,000 acres you guys have marked in your presentation, is that kind of maybe like a high-grade of position? May be the most thickest Meramec? Or is that kind of your entire position?

J. Russell Porter

No, that's the thickest Meramec on our position. We're not attempting to map it. We're not attempting to map it, and we don't have an opinion on the Meramec outside of our acreage position. We're pleased that Devon and Newfield are doing very well with it very close to us. I think it's working very well in their positions and we anticipate it's going to work very well on ours.

Operator

Our next question is from Brad Pattarozzi from Heikkinen Energy Advisors.

Brad Pattarozzi - Heikkinen Energy Advisors, LLC

Was the initial WEHLU [ph] wells having a higher oil content -- I think you've talked about thus far? What do you think is driving that and do think that is repeatable across the acreage?

J. Russell Porter

That's a good question. Early -- we're very early in the life of these wells. We've got the Lower Hunton well on a ESP. We're actually putting it on gas lift this weekend. So I think you're going to see some both the oil rates and the gas rates come up on it -- total fluid rates come up on it, because we'll have more capacity. As far as the Upper Hunton, I really don't have a good geologic explanation for why the oil cut is so high on it. We are in the most almost the most up dip position possible as you get close to that pinch out. I would expect it there to be a little bit more gas but right now, we're not seeing a whole lot of gas in that well.

Brad Pattarozzi - Heikkinen Energy Advisors, LLC

All right. And also within Hunton with the 4 wells waiting on completion and 4 wells drilling, what's the timing on getting those wells that are waiting on completion online? And also have you talked to your partner about potentially bringing in an additional frac crew to get them online sooner?

J. Russell Porter

Yes, of course, we've talked about that. And we don't like being that far behind on completions, and we'll see if we can get some additional assets put to bear there, I'll let Mike Gerlich answer the other question.

Michael A. Gerlich

Yes, kind of just looking at our 14 drilling for the remainder of the year, I'll kind of throw out some numbers here. We're looking to drill gross 52 wells. That will be 36 in Oklahoma, 16 in Appalachia. Completion wise, we're looking at 48, 34 of those in Oklahoma, 14 in Appalachia. And on production, before the end of the year, out of those 48 we should have 45, 34 in Oklahoma, 11 in Appalachia because some of those -- that we're drilling on the, the Blake pad will really move over to -- into early 2015.

J. Russell Porter

In Oklahoma, most of those completions should be fairly constant through the second half of the year. There's not pad drilling this, there's no reason that they won't just sequentially occur. As we stated in our remarks and the Marcellus, those don't come on until November and December of this year and those are pad drilling and stair step type production growth but nice volumes when it comes on.

Brad Pattarozzi - Heikkinen Energy Advisors, LLC

Okay. And one more from me, if I could. On the second [ph] Utica well, that is not in your current 2014 guidance, is that correct? I would think if you start drilling in October, when will you expect that to come online?

J. Russell Porter

We wouldn't expect it online until after the first of the year, so it's not in our production guidance.

Operator

Our next question is from Chad Mabry of MLV & Company.

Chad L. Mabry - MLV & Co LLC, Research Division

Most of mine were answered. Just to clarify, I think from the remarks on the checkerboard farm out. Is that first Woodford well still expected to spud by September 1?

J. Russell Porter

It's already spudded. They're drilling it so we should have results within I guess within the next 4 to 6 weeks.

Michael McCown

I think Russ, it's about 7,000 feet deeper, I think.

Chad L. Mabry - MLV & Co LLC, Research Division

Okay, fantastic. And then in case of mistake, did you give the well cost on the Horseshoe 3-1, it looks like you're finished drilling that.

J. Russell Porter

While, we are just through with the drilling really. We have not completed it yet but what I can say is we were just slightly over the AFE cost from the drilling standpoint, which is a significant improvement from our previously 3 operated wells. Is a bit premature to talk about total well costs since we haven't completed it.

Operator

Our next question is from Jamaal Dardar of Tudor, Pickering, Holt & Co.

Jamaal Dardar - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

I just want a little extra color on the well cost for the SIMMS U5H so far. I see you guys have about 12 million for the AFE there. I just want to see if that's still going to be the same going forward?

J. Russell Porter

Going forward, we're looking at expected 5,000 to 6,000-foot laterals with the AFE driven completion cost of about $12 million. We did spend a bit more than that on this well. Also we don't have all the invoices in yet from the completion and everything, but as I mentioned earlier, we drilled this initial well on fluids rather than air on the upper portion of the hole, which we'll drill on air going forward for the all the way down to the intermediate casing so we expect some costs savings compared to our first well. But we will be a bit over AFE on this first well but pretty confident we'll be on AFE going forward.

Michael McCown

And then also Russ, on this one, let me interject. We drilled a pilot and then took logs and then had to plug back and then kick it off, which won't happen when we're having repeatable in the development phase of the Utica.

Jamaal Dardar - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay, great. That make sense. Also, just one more for me. Just trying to figure out if capital spending increases in the second half of the year? And you talk about the different ways of raising capital to fund this. I was wondering if you have a preferred method from the list that you gave out as far as equity.

J. Russell Porter

We're not going to comment on capital market activities at this time. As we put in our Q, there's a variety of potential sources. We're not really keen on additional leverage, so we'll just have to wait and, we'll determine when and if we raise capital going forward.

Operator

Our next question is from Neal Dingmann of SunTrust.

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

Say, Russ, when you start testing the, I was wondering, on the Woodford and Meramec, when you start testing that, will that, I, guess will you have to reallocate. Depending on what you see there. How's that going to change your plans. What's sort of the timing of to start to take a look at that versus what you're already seeing in the Hunton?

J. Russell Porter

It's a good question, Neal. We're going to get several non-op data points. So they are going to give us a lot of data. We'll drill our first operated well probably the second quarter of next year. Yes, then if we have the success that the others are having, it simply adds another potential development play for us. Really looking at how do we derisk that so we can get value recognized for our shareholders. And we'll probably divert a bit of the Hunton capital and put it towards Woodford and Meramec wells, but I'll also say that if we get -- by the middle of next year if we got 3 successful Utica wells drilled, in my mind that play is de-risked because we'll have 2 in Marshall County and one in Wetzel County and when you look at our activity and the activity of others around us that play is derisked. So we really don't need to put any more capital under that until gas prices improve, until differentials improve. So we could divert some capital from the Appalachian plan into Mid-Continent if we've got additional formations to develop in the mid-continent.

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

Got it. And right now, you certain don't have any issues with the liquidity. Have you gotten I guess sooner or advance do you get plans from your non-op partners, just want to wonder how when you and Mike sort of sit down. How do you factor that into the overall -- op plan?

J. Russell Porter

We're talking to them on a continuous basis. We have technical pre spud meetings with them before every well. They can provide us with their anticipated drilling schedule. We're still responsible for a large amount of the land and permitting work so we're certainly not surprised because we're out doing the pulling and the permitting for a number of these wells, So we've got pretty good visibility. They did get a little bit more active this year then they originally projected but we're fully supportive of that because of the success they've had.

Operator

Our next question is a follow-up from Ron Mills of Johnson Rice.

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

Just a follow up on a couple of questions. On the oil cut, I guess, that Brad asked not just on WEHLU but the oil cut even on your other Hunton activity has been a little bit higher at least higher that in your type curve is that something that as you get towards year end, you may revisit the type curve not just via well performance but via the commodity mix?

J. Russell Porter

Yes, we are revisiting that, Ron, you go to remember our first type curve we put out were really based on a number of wells that were drilled in a slightly different area than the AMI. What we've seen relative to the type curve as you've point out is we've had on a volumetric basis, we are performing on average right on that type curve but on a commodity basis our oil cuts are appreciably higher than the 65% oil we originally projected. It looks we're around 75% with our oil cuts on average. We are sort of reformulating our type curves. We're going to end up with a type curve in the AMI area, a type curve in the WEHLU area, a type curve probably in Canadian County. So as we get more and more data, we'll continually refine those and keep updating you guys as we feel we've got enough data for it to be meaningful.

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

Perfect staying in Oklahoma, the Woodford well that Cimarex is drilling, you don't have an interest in of that right, you just have an interest in the offsetting checkerboard?

J. Russell Porter

Cimarex is drilling?

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

Did I say -- I'm sorry, when you have your checkerboard aren't they -- is the Woodford well drilling in your checkerboard partnership area but you do not have an interest in that Woodford, correct?

J. Russell Porter

We farm that out on checkerboard basis. We do not have working interest in the well, but we will get all the data as a part of our trade and we do own the offset acreage.

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

Okay and then just to also confirm what you said on the SIMMS well, it sounds like the plan there is to flow that back in more of a managed pressure format as opposed to just on a unrestricted basis?

J. Russell Porter

Yes, I mean, look, we'll test it and see what it looks like on an IP basis, but we're going to damage the well. We're not going to pull it hard we're certainly not going to produce it hard. This thing looks like it could have some pretty healthy deliverability, but if it's testing at X, I'm not going to have the guys open it wide open so we can get above Y to give everybody a bigger headline number. We're going to do what we think’s best for the well long term.

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

Okay. And then just based on that 2015 exit rate, really strong rate, but with the new capital budget for this year, Mike, is a fourth quarter CapEx run rate a pretty good run rate that we should assume for next year? Or how should we -- I know you don't have a budget yet, but since you're accelerating here in the back half of the year, just want to see if directionally that's what you expected to do next year?

Michael A. Gerlich

Well, obviously we are not giving guidance on CapEx for next year as you say we haven't worked through those numbers. But at this point I would say that we're going to be more consistent to this full year level with maybe a slight bias to the upside, but not a significant move up.

Operator

Our final question is from David Beard of Iberia.

David E. Beard - Iberia Capital Partners, Research Division

A lot of questions have been answered and nice quarter. But I had a big picture question in Oklahoma. When you look at the WEHLU, should we think of that as a continuation of the statistical play that you are seeing further up in the AMI?

J. Russell Porter

It's a good question, David, and we maybe are confusing folks a little bit. Really, the Lower Hunton play in WEHLU is the same as the Lower Hunton play across the rest of our acreage. Really no difference. What makes WEHLU different is that we also had the Upper Hunton potential there. And just because of the structural position in the lower Hunton, we got some nice processes development that goes along with the fractures that we normally see, but from a Lower Hunton perspective, WEHLU is just like the rest of the acreage, from an Upper Hunton perspective, it's different because it does have that Upper Hunton potential.

David E. Beard - Iberia Capital Partners, Research Division

Okay. And what should we think about the Upper Hunton as also in essence as statistical play?

J. Russell Porter

It's not as statistical because where the Upper Hunton's present, it's usually got very good porosity development. So that makes it a lot less statistical than the Lower Hunton where the Lower Hunton's reliance is simple on the fracture development and not on any metrics porosity.

David E. Beard - Iberia Capital Partners, Research Division

And then just shifting a little bit to your guidance. I wanted to get a sense of the fourth quarter relative to what you're seeing coming out of the Utica? And any color that you could give would be good. My specific questions would be would that include a full quarter of SIMMS production choked back? Or would any SIMMS fall into the third quarter? How should we think about the contribution of the Utica to the guidance?

Michael A. Gerlich

Well, basically what we've said is that the Utica well will be coming on to sales early September and so obviously, it will be there only for a portion of the third quarter and obviously should be there for the full third quarter.

J. Russell Porter

Fourth quarter.

Michael A. Gerlich

I'm sorry, fourth quarter and as far as production decline or any of that at this point we're kind of have to take a wait and see exactly what the production rates will be. We've have obviously made some assumptions based on the type curve that we put out there and really haven't varied from those at this point in regard to our guidance.

David E. Beard - Iberia Capital Partners, Research Division

Okay. So in essence a type curve like production rate is kind of assumed coming out of this first well. And we rolled that into production here at the end of the third and the full fourth quarter, is that a fair way to say it?

Michael A. Gerlich

Yes, we are basically assuming our type curve IP of the $15 million a day and kind of taking a decline from there. Hopefully, these early results look pretty positive that we can do that and better and then we will just have to see how we maintain the production, we hold back pressure maybe -- to keep it a little flat for a longer time. We will just have to wait and see.

Operator

Thank you. Mr. Porter, I will now turn the call back to you.

J. Russell Porter

Well, we've been on for 1 hour and 7 minutes, and I heard people complaining about a call yesterday that went for 1 hour and 15 minutes, so goodbye.

Operator

Thank you for joining Gastar Exploration's Second Quarter 2014 Earnings Call. If you wish to listen to the playback of the call, please dial 1 (800) 804-7944. You may now disconnect and have a great day.

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