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Executives

Anne Pearson – IR

Russ Porter – President and CEO

Mike Gerlich – VP and CFO

Analysts

Gabriele Sorbara – Imperial Capital

Ron Mills – Johnson Rice

Kim Pacanovsky – MLV & Company

Brad Pattarozzi – Tudor Pickering Holt

Neal Dingmann – SunTrust

Josh Young – Young Capital

Chad Mabry – KLR Group

Gastar Exploration Limited (GST) Q3 2012 Earnings Call November 8, 2012 10:00 AM ET

Operator

Ladies and gentlemen, thank you for standing by and welcome to the Gastar Exploration’s Third Quarter Earnings Conference Call. During today’s presentation, all participants will be in a listen-only mode. Following the presentation, the conference will be open for your questions. (Operator Instructions) Today’s conference is being recorded, November 8, 2012. I would now like to turn the conference over to Anne Pearson of DRG&L Investor Relations. Please go ahead.

Anne Pearson

Thank you, Alicia, and good morning everyone. Sorry for the delay. Before I turn the call over to management, I do have a couple of things to go over. First, a replay of the call will be available shortly by webcast on the Gastar’s IR website and a telephone replay will be available for one week. The information you need to access these is in yesterday’s news release.

Also, today’s call will contain forward-looking statements, although management believes these statements are based on reasonable expectations, they have no assurance that they will prove to be correct. These statements are subject to certain risks, uncertainties and assumptions described in the company’s 2011 Form 10-K and subsequent Qs, which are also found on the IR section of Gastar’s website. Should one or more of these risks materialize or should underlying assumptions proved to be incorrect, actual results may vary materially.

Today’s call may also include a discussion of probable or possible reserves or use terms like potential reserve, upside or other descriptions of non-proved reserves, which are more speculative than estimates of proved reserves and accordingly are subject to greater risk. Information relayed on this call speaks only of today, November 8, 2012, so any time-sensitive information will no longer be accurate or may no longer be accurate at the time of the replay.

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

Russ Porter

Thanks, Anne, and good morning, everyone. With me this morning is Mike Gerlich, our CFO. I’ll go through a review and update of our operations and Michael will follow up with a review of the third quarter financial results. Consistent with the last several quarters, we continue to deliver strong results from our operations.

Issues beyond our control like commodity prices, midstream interruptions, and meritless corporate litigation have created challenges, but we remain focused on the continued successful execution of our growth strategy and increasing the reserves production and cash flow.

Since the third quarter of 2011, we’ve grown our production 82% and continue to increase the percentage of production from higher value crude condensate and natural gas liquids. Again, this quarter, we exceeded the top end of our production guidance and produced an average of 38 million cubic feet equivalent per day.

We brought on production 9 gross or 4.5 net additional horizontal Marcellus Shale wells and we increased production volumes over 9% sequentially, even after factoring in Q3 2012 Marcellus midstream issues.

Our growth continues to be driven by the success we’re having in our liquids rich acreage in Marshall County, West Virginia. During the third quarter, approximately 33% of the production from our Marcellus wells was a combination of condensate and NGLs. Independent reservoir engineers have projected that the condensate yields will continue to increase the further west we move across our acreage.

The first 15 wells we drilled on the east side of our Marshall County acreage initially averaged approximately 25 barrels of condensate per million, compared to an average of 50 barrels of condensate per million from the last 12 wells we’ve drilled as we’ve moved west on our acreage. NGL yields continue to hold at approximately 50 barrels per million across our acreage position. This is very encouraging because we have at least 90 additional drilling locations identified on the western portion of our Marshall County leasehold acreage. We’ve been drilling these wells from pads with an average of four to six wells per pad. These wells have had an average lateral length of approximately 4,800 feet with spacing between wells of 600 feet.

After reviewing detailed core and reservoir analysis, we plan to commence drilling in December of this year on four wells on the Goudy pad with average 5,500 foot laterals, but these wells will be spaced 400 feet apart. If recoverable volumes compare favorably to our earlier wells, we may move our drilling program forward using this tighter spacing, which will allow us to drill as many as 20 to 25 additional wells on our Marshall County acreage.

We’re also experimenting with the orientation of our laterals to test if the wells will perform even better if drilled on a slightly different azimuth. This test is already underway with the five well Addison pad. We commenced drilling the top holes in October and we expect to have the five wells completed and fracked and on production by the second quarter of 2013. We’re planning to temporarily slowdown our drilling activity in Marshall County commencing late in the second quarter of 2013 to monitor the results of the tighter spacing test at the Goudy pad and the directional orientation test at the Addison pad.

Our Marshall County acreage is a great asset and our goal is to continue to employ the best drilling practices to maximize our return on investment. At current pricing, our Marcellus well economics yield an estimated 38% internal rate of return. This is based on our third-party reservoir engineering average decline curve and current NYMEX futures curve. This assumes 6.4 Bcfe EUR and an all-in well cost of $7.3 million for a 5,000 foot lateral yielding a $1.42 per MMcfe equivalent finding and development cost. We will continue to work on maximizing drilling results while and lower drilling and operating cost.

I won’t walk through all the various wells in our portfolios since we provided those details in the earnings release we filed yesterday afternoon. Currently, we have a total of 27 gross operated wells and 11 non-operated wells on production in the Marcellus Shale. We expect to have an additional 11 gross operated wells on production by the end of this year brining our total gross operated wells to 38 by year end 2012.

As we bring on this additional production, we are working with our third-party pipeline and gathering system owner Williams to make sure that they have the capacity we need to produce without being pipeline or processing constrained.

As you know for the last year, we’ve continued to be negatively impacted by production constraints associated with condensate handling, dehydration limitations and high line pressures on the Williams system plus Williams had a fire at their facility in August that resulted in the gathering system being shut down for seven days.

We estimate that due to the fire and another third-party gathering system issues, our Q3 production was reduced by approximately 5.9 million cubic feet equivalent per day. Williams has made progress in solving the line pressure problems on the existing system and expanding its capacity to better service our needs.

They are currently building an additional central receipt point or CRP at the Burch Ridge well pad including dehydration capacity and compression to ensure appropriate line pressures. The Burch Ridge CRP is scheduled to be operational before the end of this year to accommodate additional production from our wells that are currently being drilled and completed. If commissioning of that facility is delayed which looks unlikely, we may have to restrict our production in the fourth quarter of this year.

Regarding our Mid-Continent prospect, we’re continuing to build our lease position and our new oil play and we’ve expanded our area of mutual interest. As of the end of the third quarter, we had acquired approximately 30,900 gross or 12,500 net acres and we’re continuing our leasing activities. As of today, we have approximately 35,000 gross acres. We now have two additional prospect areas adjacent to the initial AMI with a current goal of leasing at least 50,000 combined gross acres within these prospect areas.

As we mentioned last quarter, we plan to drill three non-operated horizontal test wells. Fracture stimulation operations were completed on the first well in late September and preliminary flow back began in early October. The well continues to unload completion fluids, while oil and natural gas production rates continue to increase. The operator plans to drill the plugs out between these completion stages this week. We plan to update the market once we have the well cleaned up and can provide an initial production rate and 30-day production average.

We are providing additional detail on the formation or location (inaudible) since we’re still actively leasing without much competition at this time. The cost to drill and complete the first well was approximately $4.4 million gross, $2.8 million net to Gastar which was in line with our initial projected cost. The second well should be spud by the end of November with the third well expected to spud in early January at the latest. These two wells are expected to be on production in the first quarter of 2013.

In each prospect area, Gastar paid 62.5% of the first four wells gross, gross drilling and completions costs and 56.25% of the next four wells to earn a 50% working interest. For additional wells beyond the first eight in the prospect area, we are responsible for paying only 50% working interest. Third quarter capital 2012 expenditures in the Mid-Continent were $6.3 million. For the remainder of 2012, we’ve budgeted $6.7 million for drilling completion and lease acquisition cost resulted in total budget expenditures for the year of approximately$22.7 million.

In East Texas, we’re continue to defer any new drilling or significant workover completion -recompletion activity in our Bossier producing wells in the Hilltop area due to natural gas prices. Obviously, we have projects with much better economics in other areas but there is still a fair amount of activity by other operators in the area testing shallower oil producing formations. We’ll continue to monitor those activities as closely as we can and reevaluate our options based on any new information.

Regarding the Chesapeake lawsuit that I’m sure most of you are aware of and we have a detailed disclosure in our 10-Q, while there are always risks associated with lawsuits and predicting their outcome, we are confident that we have both the facts and the law on our side. Chesapeake has sued Gastar for rescission of the November 2005 agreements wherein they acquired working interest in East Texas and acquired what is now approximately 10% of our common stock.

First of all, all of the facts that Chesapeake contends for the bases of a mutual mistake were fully known to all the parties at the time of execution of the agreements. We took the additional steps of actually outlining in the agreements what actions would be required of Chesapeake if the preferential right litigation was decided in the other side’s favor. That’s exactly what happened so to claim now that there was a mutual mistake seems disingenuous at the very least. Chesapeake’s claim that there was a failure of consideration is equally weak.

They agreed to take assignment of the working interest subject to the litigation and were required as outlined in the closing agreements to assign that working interest to the plaintiff if the case was finally adjudicated against Chesapeake. Additionally, Chesapeake agreed to acquire common stock of Gastar. They received those shares and continue to hold them. Chesapeake received exactly the consideration that it bargained for in the transactions.

Finally, Chesapeake now claims that Gastar was unjustly enriched because Chesapeake was not reimbursed for a portion of its cost of drilling and completing wells on the working interest that they subsequently assigned to the plaintiff. We believe this claim should be barred by statute of limitations, but in any event it should fail for a variety of reasons, including the fact that our agreements with Chesapeake addressed the subject matter of the dispute, which should preclude any claim for unjust enrichment.

Further, Gastar was not unjustly enriched by Chesapeake’s payment of the share of cost attributable to an interest in the properties that was not owned by Gastar. To the extent, the plaintiff was enriched, we understand that Chesapeake voluntarily settled these claims against the plaintiff in the preferential rights lawsuit.

At this point, I’ll turn it over to Mike to go through the numbers, and I’ll come back on with some closing comments.

Mike Gerlich

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

Our revenue from natural gas, oil and NGL production increased 55% from a year ago to $14.8 million due to an 82% year-on-year increase in production. Virtually, all this production growth was from the Marcellus and it more than offset the continuing decline of natural gas production in East Texas, the sale of Wyoming CBM interest and the impact of lower commodity prices.

Company-wide, our average price per Mcfe with hedges was $4.25 in the third quarter. Without realized hedging, our total company price per Mcfe was $3.28. Compared to a year ago, our average sales price before the impact of hedges declined 12% and after the impact of our hedging program, it declined 15%. If you compares sequentially; however, our blended price before hedges was up 28% and up 21% after the impact of our hedges. The sequential price improvement both before and after hedges, reflects the growing proportion of higher value oil condensate and NGLs in our overall production mix.

As we complete more wells in the Marcellus, we expect our average funded price per Mcfe to continue to climb. We benefited significantly from our hedges in place to date and we continue to have a significant portion of our production hedged for the balance of 2012 and into 2013. Despite our continued production reserve growth, lower natural gas and NGL prices continue to drive asset impairment charges this year. In the third quarter, we took a $78.1 million non-cash ceiling test impairment. This followed $72.7 million impairment in the second quarter.

The SEC rules require to utilize a 12-month average of the first day of the month prices for each of the previous 12 months to assess ceiling impairments on a quarterly basis. Based on current natural gas and NGL prices, there is a reasonable likelihood that we may record an additional impairment in the fourth quarter, but it will probably be far less than the third quarter impairment. It should be noted that the ceiling test does not reflect the true market value of our assets as it’s based on historic flat pricing nor do the ceiling impairments impact our covenant compliance or future anticipated increases in our borrowing base under our revolving credit facility.

Now looking at net results. On a reported basis, our net loss for the third quarter of 2012 was $83.5 million or $1.31 per diluted share. If you exclude the impairment and the impact of unrealized hedging activity, we broke even in third quarter of 2012; that compares to an adjusted net loss of $1.4 million or $0.02 per diluted share in the third quarter of last year and $4.1 million or $0.06 per diluted share for the second quarter of 2012.

Cash flow from operations before working capital changes was $0.15 per diluted share compared to a nickel diluted share last year and $0.09 per diluted share in the previous quarter. Combined average daily production increased by 9% from the prior quarter, which exceeded our guidance of 35 million cubic feet to 37 cubic feet equivalent per day, due to production from nine new gross wells in the Marcellus since the end of the second quarter and Q3 one-time adjustments partially offset by gathering system downtime.

Production during the quarter was positively impacted by 1.4 million cubic feet equivalent per day of one-time adjustments. These adjustments were in East Texas and the result of a retroactive increase and are Belin #1 net revenue interest based on an updated division order time opinion reduced by a retroactive properties assignment. Excluding these one-time adjustments, our actual Q3 production would have been 36.6 million cubic feet equivalent per day or right in the middle of our guidance.

For the fourth quarter, we expect total company production to average between 38 million cubic feet per day and 40 million cubic feet equivalent per day. This production guidance assumes that mystery and misuse in the Marcellus will continue to improve, but downtime or line pressure curtailments included in our guidance are projected to negatively impact Marcellus production by approximately 8%. We came in on the low-end of our guidance for the percentage of total production from higher value liquids at 20%. The actual liquids percentage in the third quarter would have been 22% excluding the East Texas one-time adjustments on the Belin #1 well and property assignment.

Liquids as a percentage of total company production is expected to increase to 23% to 26% in the fourth quarter as we continue to bring on new Marcellus wells and as the natural decline the East Texas dry gas wells continues. As Russ mentioned as our drilling trends further to the west in Marshall County, we expect to encounter high yields of condensate per million cubic feet of natural gas.

Also assuming we are successful with our Mid-Continent oil play, we could see additional positive impact on our future production mix as we bring wells on from that project. So, we are hopeful that curve for liquids as a percentage of total production will continue to trend up throughout next year.

Moving to the results of our hedging program, approximately 89% of our third quarter natural gas production was hedged, which increased our revenues by approximately $2.6 million. Roughly 66% of our oil and 60% of our NGL production was hedged last quarter resulting in an increase in combined oil and NGL revenues of $818,000. We have hedges covering approximately 26,000 MMBtu per day of natural gas production for the remainder of 2012 in the form of costless three-way collars, put spreads, and call spread hedges.

For the remainder of 2012, we also have fixed price swaps for 600 barrels a day of crude at about $102 per barrel and for 250 barrels a day of NGLs at $49.59 per barrel. About half of our crude hedges are utilized to hedge the heavy NGL components of our butane, isobutane and pentanes, which currently comprise approximately 43% of our NGL production. Complete details about our hedged positions as of September 30 are available in our 10-Q, which was filed yesterday afternoon.

We continue to look for opportunities to enhance our liquids hedging positions for 2013 as our production of oil and NGLs and condensate rises. Moving to some of the key expense items in the third quarter and our guidance for the fourth quarter, our lease operating expense last quarter was significantly lower than expected about $780,000 versus our guidance of $1.9 million to $2.2 million and about one-third of our LOE expense for the same quarter a year ago. The variance to our guidance was due to lower East Texas controllable LOE of approximately $750,000 including a decrease of $394,000 resulting from property assignments.

Lower Marcellus Shale controllable LOE of approximately $250,000 due to declining water disposal cost and delays in budgeted workover expenditures and lower ad valorem taxes of approximately $140,000 resulting from a true-up taxable expense. On an Mcfe basis, LOE was $0.22 versus $0.49 in the prior quarter and $1.23 a year ago. For the fourth quarter, we expect total LOE to be in the range of $1.7 million to 1.9 million, $0.48 to $0.52 per Mcfe.

Production taxes were $0.16 per Mcfe, which is about double the rate a year ago. The increase in the rate was expected due to the fact that our Marcellus production is not exempt for production taxes while historically our East Texas production has been exempt from under the Texas tight sands credit.

For the fourth quarter, we expect the rate of approximately $0.19 per Mcfe. DD&A in the second quarter was $2.04 per Mcfe, down $0.16 from the prior quarter. This is higher than our earlier guidance of $1.80 to $1.90 due to a higher proved cost associated with allocations of undeveloped East Texas leasehold cost from unproved to proved properties that increased the current DD&A rate by approximately $0.12 per Mcfe. This sequential decline was a result of the $73 million of impairment in the second quarter. The additional $78 million impairment we booked in Q3 should decrease DD&A per unit to about $1.90 to $2 per Mcfe in the fourth quarter.

Transportation, treating and gathering expenses of $1.3 million for Q3 were in line with our previously quarterly guidance of $1.2 million to $1.3 million. For the fourth quarter, we expected it to again be in a similar range of $1.3 million to $1.4 million.

Cash, general and administrative expenses for the third quarter was $2.2 million, which is about 100,000 less than a year ago and at the high end of our guidance range of $2 million to $2.2 million. Non-cash stock compensation expense was $729,000 which was down about $225,000 from the prior quarter when we booked a true up of forfeiture rates related to restricted share vestings.

For the fourth quarter, we expect cash G&A of about $2.2 million to $2.4 million and non-cash stock compensation of about $700,000 to $800,000. Regarding the Chesapeake litigation, our current estimate of the legal cost to defend this matter to resolution is about $900,000 to $1.2 million. This range assumes that this matter goes to trial in late 2013 and thus this item of G&A cost will be spread somewhat evenly over the next five quarters.

Moving to the balance sheet, at September 30, we had cash and cash equivalents of $9.1 million and net debt of about $61 million. Back to September 30, the borrowing base on our revolving credit facility was increased from $100 million to $110 million resulting in availability of $40 million. As of this date, we continue to have $70 million of debt outstanding under our revolver and a cash balance of approximately $9 million.

The next regularly scheduled redetermination is set for May 2013. We expect to see another increase next year based on our year end reserves report as we continue to bring on additional proved, developed producing wells in the Marcellus. We had a net working capital deficit at the end of the quarter of $22.8 million, which is down almost $3 million from the prior quarter. The deficit includes advances from non-operating partners totaling about $18.4 million. During the third quarter, Gastar USA issued an additional 559,645 preferred shares for net proceeds of $10.7 million.

Since the end of the quarter, we have issued an additional 4,304 shares for net proceeds of $84,000. That brings total preferred shares issued and outstanding to 3,951,254 with a total liquidation preference of approximately $98.8 million. We have approximately 49,000 preferred shares remaining to issue.

Looking at CapEx, we spent a total of $36.1 million in the third quarter which brings our first nine months CapEx to a $105 million. For the remainder of the year, we expect to spend an additional $46.1 million, which includes $37.6 million in the Marcellus Shale, $6.7 million on the new Mid-Continent oil-focused venture, $700,000 in East Texas, and $1.1 million for capitalize interest and other cost.

We are increasing our full year 2012 capital budget from $135 million to $152 million to reflect the more rapid pace of well completions in the Marcellus than we had originally forecast and expansion of leasing activity in our Mid-Continent play. The recent increase in the borrowing base, existing cash balance coupled with a growing cash flow from operations to be more than sufficient to fund this activity.

Our preliminary estimate of 2013 CapEx is in the range of $75 million to $95 million, which is materially lower than 2012, but still supports the program and will continue our track record of volume and reserve growth. In part, this CapEx budget is estimated to be lower because we planned a temporarily slow down of our drilling activity in Marshall County during the portion of the year to allow thorough analysis of the well spacing and orientation test that Russ described earlier. We’re currently reviewing our capital plans for 2013 and plan on finalizing it in the first quarter of 2013.

Just one final item I want to address proactively before I turn it back to Russ. The Chesapeake lawsuit has had a significant impact on our stock price and the price of our preferred shares, despite our belief that it has no basis. We received a number of queries asking we were in danger being delisted from the NYSE market exchange, the answer is no. We are not pumping up against any minimum requirements for listing and we have not received any verbal or written correspondence from the Exchange, warning as of any pending, non-compliance notification.

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

Russ Porter

Thanks, Mike. As you can see from this quarter’s results, our assets are performing very well. We’re highly confident that our assets are worth substantially more than as reflected in our current share price. That is a dynamic that will be addressed as we continue to deliver operational results, continue to grow liquids as a portion of our total production, prevail in the current meritless litigation and maintain a strong balance sheet with sufficient liquidity.

Personally, I have a significant amount invested in Gastar common and preferred shares and I’ve been a recent buyer of both. Our management team receives a substantial portion of their total compensation in Gastar equity. We’re all confident in the value we’re creating and appreciate the support we’ve been hearing from our preferred and common shareholders as well as from our analysts, lenders, and even other E&P operators.

That concludes our prepared remarks this morning. And we’ll open it up the call to questions now. So, operator?

Question-and-Answer Session

Operator

Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. (Operator Instructions) And our first question comes from the line of Gabriele Sorbara with Imperial Capital. Please go ahead.

Gabriele Sorbara – Imperial Capital

Good morning, guys.

Russ Porter

Good morning.

Gabriele Sorbara – Imperial Capital

It sounds like your Marcellus CapEx is going to be front-end loaded next year, can you give a sense of the breakdown how much is going to Marcellus completions versus Mid-Continent versus other? And maybe if you can give the number of gross or net wells you expect to complete in 2013 that would be helpful?

Russ Porter

Sure. Basically what we are looking to add next year, we’re doing about 20 in West Virginia gross wells, 10 net and as far as your question on the capital expenditures associated for that for 2013, it will be about $30 million in Q1 and about $25 million in Q2.

Gabriele Sorbara – Imperial Capital

Okay, great. And the balance is for Mid-Continent?

Russ Porter

And the majority of that would be in Mid-Continent a little bit of just capitalized interest and kind of other cost.

Gabriele Sorbara – Imperial Capital

Great. That’s helpful. And then in the press release, you guys mentioned potential asset sales, could you give a little color on that and would you consider selling your Marcellus crown jewel asset, obviously, it’s worth more in my opinion than your enterprise value?

Russ Porter

Well, Gab, we’re – we will consider anything that makes sense for our shareholders. Right now, selling the Marcellus is not primarily what we’re focused on. If we undertook an asset sale, it will probably be some of our other producing assets; it would not be the Marcellus Shale. However, I agree with your contention or your proposition that the Marcellus asset standalone just Marshall and Wetzel Counties by themselves are probably worth significantly more than our enterprise value today.

Gabriele Sorbara – Imperial Capital

Great. Thank you, guys. I’ll jump back in queue.

Operator

Thank you. Our next question comes from the line of Don Crist with Johnson Rice. Please go ahead.

Ron Mills – Johnson Rice

Hey, Russ, it’s Ron.

Russ Porter

Hey, Ron.

Ron Mills – Johnson Rice

My question, please, just on the CapEx budget being pulled back just more in line to cash flows, the – in the activity that goes along with that from a production standpoint, have you all thought at least preliminarily about how that CapEx if it split kind of two-thirds, one-third, is that something that you can still move forward and achieve 10% to 20% growth or I’m just trying to get a sense of the impact of that CapEx versus this year’s (inaudible)?

Russ Porter

Yeah, Ron, we can probably look at depending on if we have any asset sales or not. With that CapEx budget, probably increase production anywhere from 10% to 30% depending on if we sold any producing assets or not. So we’re very comfortable that lowering our CapEx to an amount that’s easily funded by cash flow and what would be available under our borrowing base will allow us to continue to grow production and grow reserves. If we were to sell an asset like East Texas and we probably end up in 2013 with quite a bit of excess liquidity when you look at what our borrowing base should be by midyear to late year 2013.

Ron Mills – Johnson Rice

Okay, great. In the East or – I’m sorry – in Mid-Continent, you’re pulling back your first well now, what’s your plan, I know you’re adding more acreage, but is the plan to have a one rig program continuous, is that rig count growing or do you plan on drilling a set number of wells and pulling back and evaluating, I’m just trying to get a sense as to the activity for it.

Russ Porter

Well, we’re drilling these first three, we’re drilling these first three wells, and our plan right now for 2013 will probably 10 wells gross which would be, excuse me, eight wells gross which would be four net to us for 2013. So, with the three we’ll get this year or the third starting just after the first of the year, so we’ll have 10 or 11 wells by the end of next year in the play. Of course, that’s all predicated on the first couple of wells being successful but we certainly don’t have any indications right now that they won’t be.

Ron Mills – Johnson Rice

Okay. And then as a continuation to that and then I’ll hop off, the Mid-Continent, the incremental leasing you’re doing in that area, is it located in and around your current areas and/or is it in some of the new project areas that you mentioned in the press release?

Russ Porter

The two additional areas we’re looking at are simply step-outs from our first area. It’s just broadening our lease buy area a little bit because we think the play extends over pretty large area and it’s just staying in the same structural position that we like within the play and then expanding our leasing efforts on.

Ron Mills – Johnson Rice

Okay. Perfect. I’ll jump back in. Thank you so much.

Operator

Thank you. Our next question comes from the line of Kim Pacanovsky with MLV & Company. Please go ahead.

Kim Pacanovsky – MLV & Company

Hi. Good morning, guys. Just kind of a big picture view of how you look at your Marcellus east acreage, obviously if we have, look – oil prices over $85 that dry gas acreage unless you have a very high gas price is never going to compete with your Marshall and Wetzel acreage which – still has several years of activity there. So if you could just give us just some idea of how you look at that acreage and what kind of commodity situation you would need to go and start to develop that acreage?

Russ Porter

Sure, if you look at just looking at the dry gas Marcellus potential on that acreage, you probably need a $4.50 to $5 gas price to justify – or to allow that asset to compete for capital with our other assets, but we’ve got – our guys are doing quite a good of work right now and it looks like that there’s a pretty good chance that you’ve got Utica potential under that acreage as well and I know that people traditionally think that the Utica just extends a little bit into West Virginia, but when you look at the underlying structure the Point Pleasant and you look at the areas that are the most productive in the Utica where it’s deposited on these Point Pleasant platforms, we’ve got one of those platforms that sits right underneath our Preston-Tucker acreage. So we believe that not only do we have Marcellus development potential there but we likely have – also have some Utica potential over in that eastern acreage.

Kim Pacanovsky – MLV & Company

And would you wait for...

Russ Porter

We’ve had great Utica...

Kim Pacanovsky – MLV & Company

Sorry.

Russ Porter

We would have wait for – wait for gas prices but I was going to add, we have great Utica potential under our Marshall and Wetzel County area as well. Some of the independent reservoir engineers are telling us we probably have 8 Bcf to 10 Bcf Utica wells we could drill. That would take a lower price because we got all the infrastructure in place there.

Kim Pacanovsky – MLV & Company

Right.

Russ Porter

So – but there’s a lot of – and we’re no different from the rest of the industry that has assets up there. There’s a tremendous amount of natural gas that can be developed in that basin.

Kim Pacanovsky – MLV & Company

Okay, thanks for that. And then just my second question, can you give us some guidance on what an exit rate may looks like for 2012?

Russ Porter

Basically, looking at December probably somewhere in the 41 million to 43 million equivalents per day, 75% of that being gas and 25% or so of that being liquids.

Kim Pacanovsky – MLV & Company

Okay. Thanks guys.

Operator

Thank you. Our next question comes from the line of Brad Pattarozzi with Tudor, Pickering, & Holt. Please go ahead.

Brad Pattarozzi – Tudor Pickering Holt

Hey, good morning guys. You mentioned in the press release possibly doing additional debt comparable to the credit facility. Thinking about where your debt to capital as of Q3, what are your thoughts on doing the high yield, and how willing are you to go or where would you go from a debt to cap standpoint and still be comfortable?

Russ Porter

Well, Brad, we’re not really looking at the high yield market as a viable alternative for us because the advise we’ve been given is that to get efficient execution of that market you need to be in a $200 million to $250 million issuance range. And we are certainly not going to have that level of debt in the MC by any means or anything close to that. You sort of list in the Q and in these things any potential source of capital so someone can’t come back later and say, well, you didn’t tell us you might do that.

But if we look at any additional debt, it would probably be – at the most another $20 million or $25 million that we could do in a second lien type facility that would have a pretty reasonable borrowing cost associated with it, but I’m not telling you we’re going to do that, we’re just looking at all the potential financial – or financing methods that might be available to us and listed in there in the Q so that people don’t come back later and say hey you didn’t – you surprised me with something.

Brad Pattarozzi – Tudor Pickering Holt

Okay, fair enough. And going over to the Chesapeake lawsuit for a second, you mentioned timing of the trial late 2013, considering the overhang which is still on the stock right now, can you walk through the process of actually getting this result, and I guess also going back to the lawsuit Chesapeake filed earlier in this year which drove the stock down. Is there a summary judgment in the near term on that, and could you just walk through the process I guess of getting this resolved and behind you?

Russ Porter

Yeah, I’ll walk through the timing as this has been explained to us by our counsel. Chesapeake has filed their initial claim and they filed a motion to compel arbitration. They would like to see this issue arbitrated rather than in the Federal Court. We will file our answer to their claim, our answer to the motion to compel arbitration and a motion for summary dismissal probably in the last week of this month. At that point, the judge will determine whether he will direct this to arbitration which would be a decision that if he made it we might consider appealing or he’ll decide not to direct it to arbitration. If he does not direct it to arbitration he will have the ability to rule on our motion for summary dismissal.

If he doesn’t rule on that motion, then we would go to the process of gathering evidence, discovery, interrogatories, et cetera, which shouldn’t take a long time because this is a fairly – a very small proof of documents that this dispute is based upon and a set of facts that have been well outlined in previous litigations, so there’s really not a lot of work to do there.

So then, at that point we’d have the opportunity to file a motion for summary judgment. If that motion was not granted then you would move to a trial on the merits. A trial on the merits would be essentially the same process as you would go through an arbitration; the reason we want to stay out of arbitration is because you don’t have the opportunity for these summary judgments.

We are highly confident that whether it’s an arbitration or in the court system we’ll prevail and as I said earlier, we believe the facts and the law are on our side. So, we would like to get this resolved as quickly as possible, certainly that earliest would be probably late this year or early next year if a motion for summary dismissal is granted. I have no way of handicapping that and I’m not telling anyone that that’s likely to happen. And then after that, would be a motion for summary judgment, which will probably be midyear sort of best guess on timing.

Brad Pattarozzi – Tudor Pickering Holt

Okay. Very good. Thank you.

Operator

Thank you. Our next question comes from the line of Neal Dingmann with SunTrust. Please go ahead.

Neal Dingmann – SunTrust

Good morning, Russ and Mike. Say, hey, Russ, just a question, obviously, the Mid-Continent activity looks really interesting, just wondering – once you start seeing some results there, obviously, you’re going to drill that third well likely before the end of the year and you start seeing some of these well results, depending on those results, would that cause you to – if there is as good as potential to maybe start shifting some capital next year or how – kind of how will you look at that once some of those results start coming in and outlining the 2013 CapEx?

Russ Porter

Yeah, if the wells come in as we project sort of our un-risk case which would be 400 barrel a day IPs or better, then you would start shifting some capital over, you would actually generate higher returns than what we generate in the Marcellus right now, but you’ve got some other considerations, we’ve got operating momentum for lack of a better term in the Marcellus that you’d want to keep because we’re starting to – we’re getting more efficient almost with every well.

You would have some issues where you’d want to increase your level of activity in the Mid-Continent at a pace that allows you not to spend costs that are unnecessary or to make any operational mistakes. So, I think you would see a gradual shift of that allocation of capital. For 2013, it’s anticipated to be about two-thirds in the Marcellus, one-third in the Mid-Continent. If we see the success that we’d like to see in the Mid-Continent, I think you could easily see one that that’s closer 50-50 going forward from there.

Neal Dingmann – SunTrust

Okay and then just two follow-ups on the Marcellus, one, it didn’t seem like now the takeaway issues are not having – it doesn’t seem like they’re having – like you had earlier in the year. I guess how are you set for that going forward, I mean, I know there’s always issues that can arise, but it seems like you’ve got more optionality there, is that fair to say?

Russ Porter

Well, Williams will have the second central receipt point up hopefully by the end of this month or mid-December at the latest. That’ll give us a lot more dehyd capacity additional compression; it should drop all of our line pressures in the – across the field down to around 500 pounds, whereas we’re running 700 pounds to 900 pounds now. So that will give us another outlook for the gas if you will, should really give us the ability to operate with less downtime and fewer interruptions.

From there forward, yeah, we sat down with Williams, they understand our development plan and we’ve talked about what assets need to be in place and when the next midstream start-up or midstream development that will affect us in a positive way will be. They’re bringing on fractionation probably mid part of next year that should allow us to move the same volumes, but it gets some higher realizations for some of our liquids.

Neal Dingmann – SunTrust

Oh, great. And then last on the Marcellus, you mentioned in the press release about just doing some pretty decent things, I guess on the drilling techniques and such, what kind of confidence, I guess, will you continue to do that sort of throughout next year and again how materially different or – obviously, you can read some of the different things that you’re doing to try to improve the efficiencies and the higher EURs but maybe you could just provide a little more color around that?

Russ Porter

Okay. Right now, the two things we outlined we’re experimenting with tighter spacing between wells and we’re experimenting with a different azimuth – slightly different azimuth to the drilling. If those looked like they worked then those were pretty easy to incorporate in to our go-forward plan. We’re also making some pretty good strides on, not only on drilling times which is part of the reason why we’re increasing our CapEx this year is because we’ve just got more accomplished with the same rig than we thought we would earlier in the year. But we’re also looking at some completion tweaks where we might use some slightly different logging methods to pick our stages.

We had a recent well where we did that, we reduced the number of stages by about eight or nine from our typical number. Completed that well and it’s one of the best performing wells we’ve drilled so far. That resulted in almost $1 million savings on the completion on that well. So we’ll evaluate it, we’re going to do this – that same procedure on another well we’re going to be completing fairly soon here and if it also gives us very good results, then we’ll be in a position where we can work in a change of procedure that will probably save us $750,000 to $1 million per well going forward.

In a $7 million well, well, that’s the material savings and really bumps up your returns. So, our group in West Virginia, our staff up in Clarksburg, they’ve done a fantastic job of not only getting this project off the ground and running and dealing with all the midstream issues and all those type of things, but they’re also working very hard to get us to the point where we’re optimizing our operations as quickly as possible.

Neal Dingmann – SunTrust

Perfect. Thank you all.

Operator

Thank you. (Operator Instructions) And our next question comes from the line of Josh Young with Young Capital. Please go ahead.

Josh Young – Young Capital

Good morning, guys. So one question on the Mid-Con, can you talk about the well results that your operating partner has achieved so far in the play?

Russ Porter

Yeah, our operating partner as we’ve mentioned before, the well – our first well was – actually, they’re at ninth well, they since drilled, I guess, one more and completed it and are drilling another, so they’re on their 11th well overall. Their results have been – where the basis for why we got involved in the play, they’ve shown really continually improving results. Their two most recent wells that they’ve completed and put on production came in well above what our un-risked expectation would be. So that gives us lot of comfort in the play in general and we’re anxious to get this first well cleaned up and so we can get those results known and then known to ourselves and then known to the rest of you guys.

Josh Young – Young Capital

And then structurally your stuff is the same as similar to theirs?

Russ Porter

Yes.

Josh Young – Young Capital

Okay. And then looking through the financials in the Q, it looks like your un-hedged price realizations were really low. Can you talk about them a little bit kind of explain why you’re getting $2 gas and it looks like, I don’t know, $3 to $4 total, I guess, actually it looks like around $3 per Mcf including liquids, and then maybe talk a little about the price audit you guys were going through with Williams to see if there might have been some pricing issues with the takeaway?

Russ Porter

Yeah, well, I’m not sure what I can say other than just pointing you to what we put in the release. Our natural gas realizations without the hedging was $2.27 for the quarter. We were realizing the same differentials in East Texas and then the Marcellus as other operators in our area. With hedging, that came up to $3.20. Our Mcfe equivalent price with hedging was $4.25, so I’m not sure what comment we can make on that.

Josh Young – Young Capital

Okay, I mean I’m just – it just looks low relative to 20% of your production of liquids and if portion of that’s oil, you might expect pricing realizations to be higher than just the NYMEX or whatever price for natural gas?

Mike Gerlich

Well, we continue to have the East Texas which is a lower Btu gas compared to what we up there and then we have certain deduction and so forth that are actually reflected upon that line item, but you’ve been historically seeing that every quarter. I don’t think there’s really been a marked shift in our realizations out there in any direction.

Josh Young – Young Capital

Okay. And then, I guess, I’ll just add some more questions, it sounds like it’s probably the end of the Q&A session, can you talk a little bit about why you wouldn’t sell the Marcellus and kind of what your strategy is around divestitures. I mean, given your view that you could potentially sell it for significantly more than the enterprise value of the company out the current stock price, it seems like that would be something that’s worth evaluating and worth considering and I guess it’s a little bit confusing to see that you wouldn’t consider that and it’s not something you’re actively working on.

Russ Porter

Well, Josh, we didn’t – we did not say we wouldn’t. What I said was we’re looking at all the alternatives available to us. What I said was that was not the first thing we’re looking at right now. If someone came in and offered us what we believe the Marcellus is worth, not only the proven assets, but the development case on those assets, on the unproved assets, then we would evaluate that and if it made sense to sell it, we would do so. I mean, I’m not sure why you have the impression that we wouldn’t entertain that. Our Board is constantly looking at all alternatives.

Josh Young – Young Capital

Okay. I guess, I must have misheard what you were saying around the assets (inaudible). Thank you for answering the questions.

Russ Porter

Okay. Thanks, Josh.

Operator

Thank you. Our next question comes from the line Chad Mabry with KLR Group. Please go ahead.

Chad Mabry – KLR Group

Thanks, good morning. Quick question on CapEx, looking at your Q4 guidance in 2013, but it just looks like you’re kind of pulling forward some of that CapEx into Q4, I guess, first of all is that an accurate assessment there? And then looking into 2013, can you comment on maybe how much of that budget is discretionary to you versus kind of committed capital next year?

Russ Porter

I’ll answer the second part, then I’ll ask Mike to answer the first part, although you may have to ask it again, I wasn’t quite sure what you’re asking on the first part of it. But as far 2013 discretionary, I guess, you could say that by definition, a large portion of it is discretionary. We operate at Marcellus. There really are no penalties if we were to cut back the program further. We do have operational issues to consider like the fact that we have one of the rigs under a contract that extends it through the end of May.

So, pretty difficult to lay down that rig and pay for it on a daily basis if not use it. In the Mid-Continent, we’ve got a very cooperative relationship with the operator there. We’ve jointly developed this program. If results warranted, there’s no reason why the operator would be incentivized to drill wells that we didn’t want to drill. So I think that that’s probably as close to the discretionary definition as you can get. So, in short, a large percentage of our 2013 CapEx would be discretionary.

Chad Mabry – KLR Group

Okay, yeah, that’s kind of what I was getting at so I appreciate it.

Mike Gerlich

In regards to your question about the Marcellus capital spending, there’s really sort of multiple components going on here, as we talked about we are getting these wells down faster. If you remember our original guidance was that we’d have 34 wells on at year-end in the Marcellus, our guidance is now we’ll have 38 on and producing. So we’ve picked up some additional capital from that acceleration of that standpoint. We have built in a little bit of additional cost per acreage acquisitions that the Land Department things are bolt on in that liquids rich area. So, and then some additional infrastructures associated with that CRP build out. So all those are really what moved our capital up in the Marcellus coupled with a little extra leasing cost in the Mid-Continent area.

Chad Mabry – KLR Group

Okay. I appreciate it. And just a quick follow-up to that then, since you’re completing more wells by year end, any early indications on what that borrowing base could be increased to on the spring redetermination?

Mike Gerlich

We continue to be optimistic. It will be a better movement than what you’ve seen this time. You remember our last comments was that we saw – we’re anticipating a modest increase this time around. And then we get to the year end, we use our year end reserve report. We think it will be higher. It’s just hard to predict because – what are the banks’ price curve is going to look like and that’s just going to really be dependent upon where the futures prices are at the time.

Russ Porter

That expectation what we think borrowing basis will be is certainly built into our plan when we look at the liquidity we need to execute on the CapEx budget that we’ve given guidance on. So we’re comfortable that the borrowing base will be sufficient to allow us to expand that $75 million to $95 million in CapEx next year.

Chad Mabry – KLR Group

I appreciate it guys. Thanks.

Operator

Thank you. At this time, I would like to turn the conference back to management for any final remarks.

Russ Porter

Thank you, that was – appreciate everybody hanging in there with us for a full hour today, a little bit longer than we usually go. As usual, if you’ve got any questions or follow-up, you can contact myself or Mike here at our office and we look forward to talking to you guys soon. Thank you.

Operator

Ladies and gentlemen, this does conclude our conference for today. If you’d like to listen to a replay of today’s conference, you can find the replay information in yesterday’s earnings news release. Thank you for your participation. You may now disconnect.

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