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Executives

Mark Aydin - Manager of Investor Relations

Thomas C. Stabley - Co-Founder, Chief Executive Officer and Director

Michael L. Hodges - Chief Financial Officer

Patrick M. McKinney - President and Chief Operating Officer

Analysts

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

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

Gordon Douthat - Wells Fargo Securities, LLC, Research Division

Brian T. Velie - Capital One Southcoast, Inc., Research Division

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

Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Jeffrey Hayden

Phillip Jungwirth - BMO Capital Markets U.S.

Rex Energy (REXX) Q2 2012 Earnings Call August 8, 2012 10:00 AM ET

Operator

Good morning, ladies and gentlemen, and welcome to Rex Energy Corporation's Conference Call to discuss the company's second quarter 2012 financial results. [Operator Instructions] I would now like to turn introduce Mark Aydin, Manager, Investor Relations.

Mark Aydin

Good morning, and thank you for joining us for the Rex Energy Second Quarter 2012 Financial and Operational Update Call. On the call today is our Chief Executive Officer, Tom Stabley; our President and Chief Operating Officer, Patrick McKinney; and our Chief Financial Officer, Michael Hodges. We hope you've had time to review yesterday's 2012 second quarter operational and financial release.

Today's discussion will include forward-looking information and reference to non-GAAP financial measures. You should refer to the disclosures in our 2011 Form 10-K and other SEC filings regarding factors that could cause our future results to differ from this forward-looking information. A reconciliation of non-GAAP financial measures can be found on our website and in our 8-K filed yesterday with the SEC. We've also included additional information in the presentation materials posted to our website to help you analyze the company's performance.

I would like to now turn the call over to our Chief Executive Officer, Tom Stabley.

Thomas C. Stabley

Thank you, and good morning. Starting with Slide 4, we have provided a summary of highlights for the second quarter. Production came in at 62.5 million cubic feet equivalent per day, which is a 78% growth over the comparable quarter last year, including 14% growth in liquids and 122% growth in natural gas. Our production rate of 62.5 million cubic feet equivalent per day was at the midpoint of our previous issued guidance range of 61 million to 66 million cubic feet equivalent per day.

Second quarter production was up 3% quarter-over-quarter, and this was with constrained production of an estimated 1.2 million to 1.8 million cubic feet equivalent per day due to involuntary curtailments in our non-operated areas in Westmoreland, Pennsylvania and extended downtime associated with the start-up of the recently commissioned Bluestone Plant. We continue to see some limited restrictions in our Westmoreland non-operated areas. However, our Butler operations are now flowing outgoing without restrictions.

During the quarter, we also completed the sale of our Butler County midstream assets to MarkWest Energy for cash proceeds of approximately $121 million, exceeding the previously announced range of $90 million to $110 million in combined proceeds from the sale of the midstream assets and the Rockies assets.

With the transaction complete and MarkWest plans to compete their NGL pipeline to their Keystone facilities by the end of 2013, Rex is now focused on establishing its ethane markets for our Butler product in Butler County. Just as a reminder, we currently receive minimal value for our ethane, either in reserves or sales, since the majority of our ethane is used as fuel in plant compressors.

In addition to the ethane sales, with the completion of the MarkWest NGL pipeline, Rex expects to receive approximately $0.23 per gallon in transportation cost savings for its C3 plus stream. So we remain very excited about the partnership with MarkWest and continue to believe it will help us fully develop the potential of our Butler Operated Area.

Turning to our Butler Operated Area, we now have a full year production on the Behm #1H well. As a reminder, the well has a lateral length of 3,900 feet and was completed utilizing our "Super Frac" design. As of June 30 and after one year of production data, the well is trending in line with an approximate 8 Bcfe type curve. These results are similar to what we previously announced for the Drushel 3H well, which we also completed using the "Super Frac" method.

In addition to these 2 wells, we recently completed 2 wells on the Carson pad using enhanced "Super Frac" completion design. And while we only have 45 days of production data, we are pleased with the results we have seen so far. We are planning to utilize this "Super Frac" completion design on 4 more wells in 2012. Once we have analyzed the results from these wells, engage the additional production from the 4 wells we already have completed with the "Super Frac" design, we'll be in a better position to discuss reserve impacts from the new design. We're expecting to have our initial evaluation done by year end.

Also in Butler County, we placed into sales all 6 wells on the Gilliland pad, including the Gilliland 11HB, the company's first test of the Upper Devonian Burkett shale. The Gilliland 11HB has been shut-in following its completion and has produced at a restricted rate of approximately 3.2 million cubic feet equivalent per day for a 2,700-foot lateral. Patrick will provide more color on the Gilliland later in the call.

Finally, in our Butler Operated Area, while the majority of our operations are focused on our core Marcellus development, we're planning to do -- drill 2 wells this year to test for increased or Super Rich liquids content in the northwest portion of our acreage. One is our second Upper Devonian Burkett test well and one is our Marcellus well. Both of the test wells are expected to help us further delineate our areas of increased or Super Rich liquids content.

Moving to the Ohio Utica. And to clarify, any confusion that may exist, we have completed and fracture stimulated the first Ohio Utica well in the Warrior Prospect in Carroll County, the Brace #1H at the end of June 2012. The well is currently being shut-in for 60 days to allow for the dissipation of frac fluids and is also being hooked into sales. Currently, we expect the first sales in September of 2012. This remains on schedule with our previously announced plans, and we expect to provide an update on the well in our next quarterly conference call.

We have started our first of 3 commitment wells in the Warrior South Prospect, the Guernsey #1H, and expect to complete the drilling operations on all 3 wells in the third quarter of 2012. We currently expect to fracture stimulate 1 of the 3 Warrior South wells during the fourth quarter.

Finally, in last night's release, we announced that total net acreage in Rex's Warrior Prospects at the end of Q2 is approximately 18,500 net acres, and the company expects to reach 20,000 net acres by year end in the 2 project areas.

Also, in last evening's release, we announced an increase to our capital budget, with a portion of the increase dedicated to projects in the Illinois Basin. Included in that amount is up to $7 million allocated to our conventional oil production in the basin.

During the second quarter, our technical team began a review of the Illinois Basin assets and identified an area in Indiana where we believe there's an opportunity for bypass pay and infill drilling. We've tested the area on a small scale and believe that these drilling and recompletion projects could potentially add an estimated 250 to 400 gross barrels of oil per day by the fourth quarter. As with other basins, the Illinois Basin has the opportunity to provide multiple zones, and our technical team will continue their assessment of these multi-zones to identify additional opportunities in the basin.

Finally, we are pleased to announce we are increasing our full year 2012 production guidance to a range of 68 million to 73 million cubic feet equivalent per day from our previous guidance of 67 million to 72 million cubic feet equivalent per day. The increase is a result of continued strong results in the Butler Operated Area and additional development drilling in the Illinois Basin. In addition, we are targeting our 2012 production exit rate to have a liquids component in excess of 30%.

I would now like to turn the call over to our Chief Financial Officer, Michael Hodges.

Michael L. Hodges

Thanks, Tom. Moving on to Slide 5, I would like to review some of the operational and financial highlights for the quarter. As Tom mentioned earlier, our average daily production increased 3% over the first quarter of 2012 and 78% over the second quarter of 2011. Oil and NGL production for the quarter accounted for 26% of our total production, which is right in line with where we were at in first quarter. As Tom mentioned earlier, we expect our production mix to turn significantly towards liquids in the second half of the year, finishing the year with more than 30% of our total production by volume from liquids.

Lease operating expenses for the quarter were $11 million or approximately $1.93 per Mcfe and at the midpoint of our guidance range. The $1.93 per Mcfe is a 22% decrease on a per-unit basis as compared to the second quarter of 2011. Strong production from our additional Marcellus wells and lower operating costs from existing wells contributed to the improvement on a per-unit basis over the second quarter of 2011.

Adjusted net income from continuing operations for the quarter was approximately $600,000 or $0.01 per share. EBITDAX from continuing operations, a non-GAAP measure, was approximately $18 million for the second quarter or $0.34 per share, which is a 10% increase per share over the second quarter of 2011. For a detailed reconciliation of these non-GAAP measures to GAAP net income, please see the appendix at the end of our corporate presentation.

Moving to Slide 6, we present a summary of our price realizations for the second quarter. Prior to the effects of hedging, realized prices for the quarter were $89.97 per barrel for oil and condensate, $2.41 per Mcf for natural gas and $30.39 per barrel of NGLs. As we previously reported, realized NGL prices were impacted during the quarter by weakness in the propane market.

In addition, the combination of unanticipated maintenance for the Sarsen depropanizer and an extended commissioning of the Bluestone Plant resulted in an increase in volumes of propane, blended into the NGL stream and filled outside of the premium local markets. We believe these sales have since been resolved, and we expect the third quarter sales of propane to benefit from increased operational efficiencies.

Cash settlements from hedges increased our realized gas price by $1.25 per Mcf for the quarter, resulting in a net price of $3.66 per Mcf. Realized prices for NGLs were also positively impacted by hedging activities during the quarter, increasing our realized price by $1.22 to $31.61 per barrel. Results from our oil hedges caused a slight decrease of $0.44 per barrel in our net realized price for the quarter.

Moving on to Slide 7, we provide the current hedging summary. We currently have 73% of our 2012 oil production hedged, with an average price of about $68 per barrel on the floor and average ceiling of approximately $111 per barrel. In addition, we currently have 62% of our gas production hedged, with an average floor price of $4.37 per Mcf and a ceiling price of $4.81 per Mcf. In the second quarter, we added natural gas liquids hedges to our hedge position, with 23% of our current production hedged with an average price of $1.03 per gallon or $43.26 per barrel.

For 2013, we currently have 68% of our crude oil hedge, with an average floor of $72 per barrel and an average ceiling of $113 per barrel. We also have 78% of our 2013 gas production hedged with an average floor of $4.35 and a ceiling price of $4.59, and 25% of our NGL production is currently hedged with an average price per gallon of $1.03.

We recently began the process of hedging additional natural gas production in 2014. As of today, we have 23% of current gas production hedged at a floor price of $3.48 per Mcf and a ceiling price of $4.11 per Mcf. All percentage estimates are based on the midpoint of our third quarter production guidance. As additional opportunities become available, we will continue to add to our hedge position.

We are very pleased with our existing hedge book, and we feel it provides a strong cash flow base to protect our current borrowing base and to execute on current and future capital plans. For more detailed information on our hedging position, please see our appendix at the end of our corporate presentation posted to our website.

Moving on to Slide 8 (sic) [32] we would like to discuss our third quarter 2012 guidance and our updated full year 2012 guidance. We expect third quarter daily production to average between 73 million and 76 million cubic feet of equivalent per day. For the year, as Tom mentioned earlier, we're increasing our average daily production guidance to a range of 68 million to 73 million cubic feet equivalent per day, due to our strong operational results.

Third quarter lease operating expenses are expected to be in the range of $11 million to $13 million. Cash G&A for the third quarter is expected to be within a range of $6 million to $7 million. For 2012, we are lowering our LOE guidance range to $46 million to $50 million as compared to our previous range of $48 million to $53 million. We're maintaining our full year cash G&A guidance range of $20 million to $24 million.

Slide 9 (sic) [13] presents our operating capital budget for 2012, which we are increasing from $155 million to $180 million. This increase is the result of additional high rate of return developmental oil drilling in the Illinois Basin, higher incremental well costs from our "Super Frac" design on certain wells in the Butler Operated Area and additional investments to support the growth of our water management services subsidiary. We're projecting to spend approximately 89% of our capital budget in our operating areas, and 89% of that will be devoted to oil and liquid-rich projects.

Also of note is the recent growth of our water management subsidiary. We are extremely pleased with the performance of this business to date, and we have allocated our 2012 capital accordingly. We expect this business will generate more than $10 million in third-party revenues this year at very strong margins, and we are looking for continued growth from this business into 2013. More information on our 2012 capital budget is available in our August corporate presentation, which can be accessed on our company website.

I will now turn the call over to Patrick McKinney, our President and Chief Operating Officer.

Patrick M. McKinney

Thanks, Michael. Looking at Slide 10 (sic) [17] on our operated area in Butler and following on the opening comments that Tom has discussed, we're extremely excited to continue to increase the reserves and liquids potential of this area.

The Behm #1H "Super Frac" well has been on production now for over a year and is trending on the 8 Bcfe type curve demonstrated at the Drushel #3H well. Our most recent "Super Frac" wells, the Carson 1H and 3H, have both been on production approximately 60 days, and their preliminary production rates and pressure profiles are very encouraging.

The 5 Marcellus wells on the Gilliland pad were completed and placed into sales during the second quarter and were producing at uninterrupted rates of combined of 19 million cubic feet equivalent per day, while we were commissioning the Bluestone Plant. Similarly, we had uninterrupted rates from the company's first Upper Devonian Burkett test, the Gilliland 11HB, which produced at 3.2 million cubic feet equivalent per day and had an increased liquids content 16% higher than adjacent Marcellus wells.

We plan to continue testing the northwest area of our Butler County holdings for increased liquids concentrations in the fourth quarter of 2012. We will grow our second Upper Devonian Burkett test at the Burgh location and drill a Super Rich Marcellus well at the Grubbs location. We also are going to test the Upper Devonian Rhinestreet formation, our legacy vertical well.

We drilled and cased our second dry gas Utica well, the Hufnagel 1H in the second quarter. The well encountered a similar section of combined Point Pleasant and Utica interval as we saw in our Cheeseman 1H well. The Hufnagel will be fracture simulated in 2013.

Our initial Utica well, the Cheeseman 1H, has performed well over the last 120-day period. We will continue to monitor the well and expect to be in better position to evaluate the Utica resource potential of our acreage by year end.

For the full year, we plan to drill 20 gross wells in Butler, frac 19 and place a total of 19 into service. Our year-end inventories of wells drilled and awaiting completion now stands at 18.

Slide 11 (sic) [18] summarizes where we feel we were at with our "Super Frac" well results after including the Beam 1H full year of production history with that of Drushel 3H. The production graph in the lower right inset shows the actual production of the 2 wells over the course of their first year production. The wells actual production is plotted against the 8 Bcfe type curve based on projected year-end 2012 SEC pricing of $2.85 per Mcf.

The dash line below is the type curve that represents our 2011 year-end proved reserve type curve of 5.3 Bcfe. You can see that the 8 Bcfe type curve has a much shallower first year decline at 37% versus 66%. This shallower decline allows for 30% more production to be realized in year one. You will note that our 30-day initial sales rate remains unchanged at 3.4 million cubic feet per day at the wellhead.

The new "Super Frac" type curve considerations are listed in the summary above the graph. Our lateral length proxy is now up 14% to 4,000 feet. We've increased the number of frac stages by 82% to 23. Our sand concentration is up 34% to over 6 million pounds.

Our new 4,000-foot, 23-stage "Super Frac" well cost is now estimated in a range between $6.2 million to $6.4 million or an increase of 17% to 21%. This gives us a 51% increase in EUR 8 Bcfe and a 24% liquids content without ethane recovery. While considering full ethane recovery, the EUR grows to 11 Bcfe, yielding a 45% liquids strength.

The incremental capital cost is most certainly accretive. Moreover, if we continue to see these type of well results, our point-forward capital efficiency should improve tremendously, as we will be able to grow fewer total wells to recover our full resource potential.

As mentioned above, the 2 Carson wells have been on production roughly 60 days. While we are pleased with the initial production pressure profiles of the well, as we've said on earlier calls, we feel we needed extended production history to match the curves. So it's too early to make the final call on EUR on these wells. We have 2 more "Super Frac" test this year at the 2-well Pallack pad and the 2-well Plesniak pad, both scheduled in the third quarter.

Moving to Slide 12 (sic) [19], We are continuing to gather data points to support increasing liquids concentrations in the northwest portion of our Butler acreage. As mentioned earlier, Upper Devonian Burkett test of the Gilliland 11HB contains a wet gas stream that yielded 16% more C3 plus than adjacent Marcellus wells. If you look at the vertical stratigraphic column, you can see the Burkett formation lies approximately 200 feet higher up in the section than the Marcellus interval.

Looking at the subsea contours depicted on the map, indicating where the Wack and Grubbs well locations are, they lie approximately 250 feet up dip to the existing Marcellus well locations. If our up dip increasing liquids theory is correct, these wells should contain similar liquids concentration to the test at Gilliland 11HB or be up approximately 15%.

Similarly, when you locate the Burgh Upper Devonian test location, it should be approximately 450 feet higher than the current Marcellus wells and yield an increase of up to 30% more liquids. This would have a dramatic impact on increasing liquids production and proved reserves.

Moving to Slide 13 (sic) [23], we have an update on our Warrior Prospect in Carroll County, Ohio. We closed on another 400 acres during the second quarter, bringing our total leasehold in the Warrior Prospect over 15,000 acres. We drilled and completed our first well with Brace 1H, which encountered over 135 feet of net Point Pleasant formation and 143 feet of Utica pay zone.

The well had a lateral length of 4,175 feet and was fracture stimulated with 17 stages. The well has been shut-in since late June, as Tom mentioned, and we expect to have our first sales beginning September on schedule.

Recall that we have estimated that we have over 100 net drilling locations in our Warrior North Prospect, and we're working with Dominion East Ohio on laying the wet gas sales line in the area to get full liquids recovery at the point of first sales.

On Slide 14 (sic) [24], we provide an update on our Warrior South Prospect in which we added another 300 acres during the second quarter. We're currently drilling our first well Warrior South, the Guernsey #1. It is the first well of our 3 well commitment in the area. All 3 wells will be drilled in the third quarter, and we currently plan to frac one of these wells in the fourth quarter. We are working with midstream providers in the region to secure wet gas transportation processing capability to further our Warrior South development. We continue to actively pursue acreage in this area.

Moving to Slide 15 (sic) [25]. As Tom mentioned in his remarks, part of Rex Energy's continued focus on growing its liquids production, our technical teams have identified a number of recompletions and infill drilling opportunities in Gibson and Posey Counties in Indiana.

Rex has over 23,000 net acres in the basin with approximately 10,000 acres outside of the Lawrence Field. This basin is similar to the other large mature basins like the Permian, for example, with multiple stack pays and a long history of conventional development.

The company currently plans to drill 7 new infill wells and recomplete 7 existing producers in the area. Approximately $7 million of capital has been allocated to these projects, and we estimate that this could conservatively add 250 to 400 gross barrels of oil per day in the fourth quarter. Based on the continued success with this work, we'll continue to evaluate additional liquids opportunities throughout as our existing acreage we have in the basin.

Slide 16 (sic) [26] gives us an update on our ASP project in the Illinois basin. We commenced ASP flooding on the Perkins-Smith Unit during the second quarter on schedule. Rex expects to see an additional response from the project in the second quarter of 2013.

In the high impact Delta Unit, we commenced drilling our pattern-injection producing wells in the second quarter, and we'll continue drilling during the third quarter. We are continuing to perform core flood work in the Delta Unit and expect to be able to book proved reserves on this project as early as year-end 2012.

Full ASP injection in the Delta Unit is still on schedule to begin in the second quarter of 2013 with initial response anticipated in 2014. Peak response at an estimated 13% of pore volume recovered is expecting to recur in mid-2015 at a rate of approximately 1,000 gross barrels of oil per day.

For the second quarter of 2012, our Middagh ASP pilot averaged 50.1 gross barrels of oil per day. The pilot continues to support the 2011 year-end proved reserve booking of 13% of pore volume recovery. The company believes the ASP projects have the potential to double the current Lawrence Field production by the end of 2015.

On Slide 17 (sic) [29], we have an update on our non-operated area in Westmoreland, Clearfield and Centre Counties. In the Westmoreland area, the previously announced 7 wells on the Marco #1 pad and National Metals #1 pad have now been producing over 150 days, and the average cumulative production is still trending 50% above the type curve.

We also would like to note that Williams, the operator, performed reduced cluster spacing treatments on 2 National Metals wells. In addition, the EURs on the last 12 wells completed by Williams are all exceeding a 6 Bcf type curve.

As we have mentioned in our previous calls, when we start approaching EUR levels such as these, even though this is a dry gas area, we feel this asset has tremendous value for Rex in the future. As previously announced, last quarter, Williams has done drilling and frac-ing for the remainder of the year.

At this point, I'd like now to turn the call back over to Tom.

Thomas C. Stabley

Thanks, Pat. We're very excited about the developments of this quarter and see numerous catalysts for the continued growth of Rex Energy. I'll briefly talk to you through a couple of the near-term catalysts. We'll have the results from our first Ohio Utica shale well, the Brace #1H, during the third quarter, and we expect to see first sales from this well in September of 2012.

We are excited about the enhancements we are seeing in our Butler Operated assets, in particular the increased EURs we are getting from our "Super Frac" completion methods, and we will be conducting further tests to the Burkett Shale, as well as testing for the Super Rich Marcellus and Rhinestreet Shale. If successful, we could have 4 prospective drilling horizons in our Butler Operated Area.

Our activities in the Illinois Basin, including targeting increased conventional drilling and execution of our ASP project, have the potential to provide a significant increase to our oil production in 2012.

We have maintained a strong liquidity position in 2012, and we'll do so going into 2013. We expect to have approximately $200 million in liquidity at the start of 2013 with 71% of our 2012 production on an Mcfe basis hedged and any increases to our borrowing base will only further enhance our liquidity. Finally, in keeping with our continued focus on growing our liquids profile, we expect our 2012 liquid exit rate to be in excess of 30%.

With that, I would like to open it up the line for question-and-answer session at this time.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Leo Mariani from RBC.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Just a question on CapEx here. How much incremental dollars you're allocating to the water subsidiary, and how much kind of money are you spending there in total on your water assets? And can you just give us kind of some strategic thoughts on what the direction of that asset could be in the next couple of years?

Thomas C. Stabley

Yes, surely. The total amount of capital allocated to water subsidiary is about $3 million. Revenue for this for the first half of the year was about $5 million. Expenses were about $3 million. So as Michael said, at $10 million total, you can expect cash flows from that asset somewhere in the area of about $4 million to $5 million, so certainly more than covering the $3 million in capital expenditures. That entity was originally started out as a water transfer and sourcing business, primarily for Rex. We're partnered with a small group of individuals in Pennsylvania. Rex owns about 60% of the total business. And the plan is now -- third-party is about 80% as oppose to originally where Rex was 80%, and we're very excited about the growth that we've seen in that area. It's managed by a completely different group. Rex is part of the board. So we meet on a regular basis. But the plan is to continue to grow that asset throughout Pennsylvania and, ultimately, get into Ohio.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay, that's helpful. So I guess it sounds like really the majority of the CapEx increase that you guys discussed was really just due to "Super Frac" on a much larger percentage of your wells than the higher well costs there?

Patrick M. McKinney

No, Leo. This is Pat. Yes, that's a piece of it, obviously, and then the $7 million in Illinois on the conventional drilling. We also added about $4 million on our tertiary recovery side, as about half of that amount is pulled forward and little acceleration from '13 and the other half is additional core flood testing and a few more development well drilling. So I think that pretty much gives you the incremental total.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay, that's great. In terms of acreage, I think you guys picked up a fair bit during the quarter here. Just -- you guys I guess have a target. As well to pick up more acreage, you talked about adding in Warrior South and the Utica. I guess are you still targeting adding acreage in Butler, and how much acreage do you think you could add in Butler over the course of the next, call it, 6 months? And what are you guys paying right now on Butler for acreage?

Thomas C. Stabley

Yes, that's a great question. We are continuing to pick up acreage in Butler County. I will tell you the primary focus in Butler County remains, as we've continued to say, adding additional drilling locations to our units. So picking up small amounts of acreage where we're already going to form a unit to drill that will add incremental locations to those units. As far as total amounts, I mean, we're going to continue to be inquisitive. As far as the rest of the year, I think we've picked up about 1,500 year-to-date. We may pick up another 1,500 or 2,000 throughout the rest of the year. As far as pricing goes, we're not going to talk too much about that. I think it's going to be similar to what you saw in the first half of the year.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. And I guess -- could you give us a little more color on the midstream potential solutions here at both Warrior South and kind of Warrior North? I know you guys are talking to a number of different providers. When do you guys think you'd be in a position to really get all your volumes handled out of both of those areas?

Thomas C. Stabley

Sure. Well, on the Warrior North project, as we said all along, we currently have 15 million a day of takeaway capacity out of that area for the wet gas stream that takes us down to the Dominion atrium facility. So the takeaway on that well and the program for next year is initially covered with those volumes. Obviously, we'll have to get some incremental as we continue to ramp up there in 2013, and it's something we'll take a look at. As far as Warrior South goes, the MarkWest plants, they're coming in Cadiz in Harrison County, and then Noble have lines that run directly through our acreage. So as we previously mentioned on our announcement with the deal on the midstream in Butler, we are talking to the MarkWest group about possibly something in that area.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

All right. And you think that's probably -- any timeframe on that? Is that going to be first half of '13, second half? Just can you give us any big picture guidance there?

Thomas C. Stabley

Well, as far as that goes, we're -- our first sale is that well is going to be frac-ed in the fourth quarter. If you assume a 60-day resting period, you'd have something early in the first quarter of '13.

Operator

Our next question comes from Ron Mills from Johnson Rice.

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

On the Utica, you've had some recent results both by private operators and by another public company last night. I don't think there has been any questions about your Carroll County acreage. But recent results in the Utica with really strong results seem to book into your Warrior South acreage. Any commentary about recent industry activity and results, and how that changes your opinion or impression of your acreage? Because it would seem that recent events have really pulled all your Utica acreage into becoming more core as oppose to just your Warrior North. Any commentary around that?

Patrick M. McKinney

Ron, this is Pat. We're in the process of drilling our first well down on the Guernsey 1, and so we'll have our -- internally, a little bit more color on what that section looks like here shortly and we're going to do some sidewall coring. But we feel great about the outside operator information that's been put out there in the public, and we feel really good about the area. And we'll have some internal confirmation here once we get that well to TD, and we can take a look at it for ourselves.

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

And when you look it at that position, even up in Carroll County, what -- there's been some variability in terms of gas versus NGLs versus oil. When you evaluate your acreage, do you have a pretty good average in terms of what you're accepting? Or how quickly does that production mix change as you move west to east on your position?

Patrick M. McKinney

Well, I think if you look at in our corporate presentation, where we kind of draw the liquids-rich window, we feel pretty comfortable Warrior South is kind of on trend to be of -- in a similar range to the Buell and, obviously, the most recent Gulfport well. When you get up into Caroll, you've got enough Chesapeake production around to feel pretty good about rates and GORs and liquid concentrations up there. So we feel we're getting more data, and we feel pretty comfortable in the ranges that's kind of been reported out there today.

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

Okay, good. Second, just on the Carson, on the "Super Fracs." The -- they've been on for 60 days. I know you still want more data. But if you go back and compare those to the Drushel and the Behm, how are those Carson wells performing relative to those first 2 wells after 60 days?

Patrick M. McKinney

Like we've said, I mean, we really like the initial production profiles that we're seeing and probably, more importantly, the pressure profile, and so we need some more time to go and see where those things are going to lay out on the lines. Just recall, too, both those jobs, we had different spacing on those jobs. The 3H, I believe, was the 150-foot spacing, and the other well was 225. So I would expect to see a little bit variation between those 2, and so we're in the process of taking a look at that and really seeing what they look like. Yes, the 3H was 150-foot design, 21 stages -- or excuse me, the 3H was 150 design, 3,900-foot lateral, 26 stages. The Carson 1H was a 225-foot design, 4,500-foot, 20 stages. So I would expect the production profiles over time to be slightly different on those.

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

Okay. And then when you talk about the Upper Devonian, the Burkett, it's a couple 200, 250 feet shallower than the Marcellus, and you had 16% incremental liquids. You highlight moving up to the north and west, and it sounds like the Marcellus will be at a similar depth profile as the Burkett was. Are you expecting similar liquids uplift as you drill those Marcellus wells? And can we also make the leap that because the Burgh well is going to test the Upper Devonian even shallower, that there's a chance they can have even more liquids?

Patrick M. McKinney

I mean, yes, there's a chance, Ron. Recall, we know where the vertical sections are because we drilled our Cheeseman well. You can see it on the slides. That's up there to the far northwest. So we know -- we feel pretty confident on the subsea depths that we're mapping. It's just a matter of -- to see if that liquids concentration continues to move the way we think it's going to. I mean, that's our hope. That's our thesis. But to be sure, we really feel that this northwest area is going to have a increased liquids content over the kind of the core or the middle part of our field.

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

And then lastly, just on NGL pricing. How quickly do you think you can get back to that $0.23 per gallon incremental costs and get more in line with some of the other producers' NGL prices in the Marcellus? And what are the steps to get that $0.23 per gallon back?

Thomas C. Stabley

Yes. Ron, it's Tom. There's really 2 steps to get to that $0.23. The first step is in the end of March 2013 when our current contract expires on the marketing side. We will begin trucking our liquids from the Butler area all the way to the Houston facilities of MarkWest and processing our liquids down at that area. That should save us just probably $0.15, somewhere between $0.14 and $0.16 a gallon in real costs that we currently experience to get it all the way to Chicago for the Aux Sable facility. And then as MarkWest talked about on their most recent call, their liquid line to the Keystone facilities is expected to be in place by the end of 2013. Once that's completed, that will eliminate the trucking as well and get us the additional approximately $0.06 to $0.08 for the total of $0.23 piping it directly into the Houston facilities. In addition, that will give us the opportunity to market the ethane as well, the beginning part of 2014. And as we mentioned, we're in the process of working on those ethane markets as we speak.

Operator

Our next question comes from Gordon Douthat from Wells Fargo.

Gordon Douthat - Wells Fargo Securities, LLC, Research Division

So I guess another question on the Upper Devonian. I know it's early but as -- if results do continue to come in, as you've seen them thus far, how much of a -- how much of the program going forward could this Upper Devonian Burkett Shale and Rhinestreet, et cetera, comprise in 2013?

Thomas C. Stabley

As far as the budgets goes?

Gordon Douthat - Wells Fargo Securities, LLC, Research Division

Yes, and just your activity levels. Would you look to -- instead of drilling Marcellus wells, would you look to drill more of the liquids wells? Does that -- the NGL marketing kind of factor into the timing of that as well? Just trying to get a sense on where that -- you say you're targeting a 30% liquids -- exiting near 30% liquids. So how could that percentage change looking forward?

Thomas C. Stabley

What we continue to have in 2013, a drilling program that's focused on holding at leases and lease expiries. We certainly -- as we lay out that program, we'll take into account the increased liquids that we're seeing, and we get these further tests as we move up into the northwest portion of the acreage. But obviously, those will all be factors when we make the decision for '13 as far as whether it's on Marcellus or on Upper Devonian. But I think we just need some additional testing at this point before we can make those -- make that call.

Gordon Douthat - Wells Fargo Securities, LLC, Research Division

Okay. And then am I correct, you do hold your acreage by drilling any of those formations? Is that correct?

Thomas C. Stabley

That's correct. So one well drilled to any depth will hold all levels in approximately 95% of our acreage. So there is a very small amount that has some few clauses on it. But for the most part, that's true.

Operator

Our next question comes from Brian Velie from Capital One South.

Brian T. Velie - Capital One Southcoast, Inc., Research Division

I got a couple of quick questions. On the "Super Frac" wells, is this -- I want to make sure I'm thinking it correctly. Is this the kind of thing that I should think of as the new normal as you get the results lined out or the new completion method lined out, so that in the future, all the wells will have similar expectations to overseeing it from "Super Frac", or is there some percentage of your well location inventory more a candidate for the "Super Frac" than others?

Patrick M. McKinney

Brian, this is Pat. That's a good question. We -- for example, the Graham fracs that we've just done, those wells were drilled last year, and they were 500-foot spacing. And so they were done with more conventional frac jobs on them. I think what our feeling is, is we got to go through and continue to see the well performance. We're going to have -- continue to see the Carson well results, and we've got 4 more jobs to do out there at the Pallack and Plesniak pads. And our goal is to take all the information as we get to the end of the year, come up with and do some modeling on what the -- what those jobs contribute, what the spacing is going to be and then consolidate all of that in our year-end reserves. So I think as we get to the end of the year, we'll be able to answer that question a lot better. But clearly, the initial results from just from a capital efficiency standpoint going forward is very compelling to us to be able to go and capture our resource potential out there with a lot fewer wells. So that would be our goal, is to try to get to that and come up with the optimal job design and spacing to be able to maximize our efficiency.

Brian T. Velie - Capital One Southcoast, Inc., Research Division

Okay, great. So I guess as I think about the Super Rich wells, those will be contingent on -- that those potential wells will be contingent on the geographic location, but the "Super Frac" wells, the goal will be to get all of them kind of heading in that direction in the future?

Patrick M. McKinney

Yes. Again, we're going to come up with what we think the optimal job design is to go and maximize our lateral lengths. There's a couple of pieces in there. One is the increased lateral length, to have an average now of 4,000 feet from 3,500 feet. And then in that 4,000-foot lateral, maximize the same placement to get the best possible well results.

Brian T. Velie - Capital One Southcoast, Inc., Research Division

Okay, great. And then the -- I guess what's your learning -- or what you've already learned, even from the "Super Frac" technique, is that -- do you think something that you can reapply in Westmoreland, where EURs are already trending to the point where, like you said earlier, they're making dry gas wells economic? If you -- or is there a potential to get "Super Frac" technology over there and make them -- maybe make that more an area of activity here in the near future?

Patrick M. McKinney

Well, we did mention that Williams has done a couple of "Super Frac" or RCS out there, and I think they're in the same position we are of trying to evaluate the results and really seeing the benefits of it. So I would say the answer is yes. I think you can apply this to really any of the intervals that we're looking at in our portfolio.

Brian T. Velie - Capital One Southcoast, Inc., Research Division

Okay, great. Sorry if I missed that. And then finally, there are a lot of different, I guess, ways to look at percent of liquids in the future. And I know that in 2014, you have a pretty good step change with ethane becoming more marketable. On the Butler County acreage in the past, I think you said that about 1/3 of that acreage was prospective for the Super Rich area. And that was early on, so I don't know if that changed. But what do you use as your long-term expectation for Butler County liquids percentage?

Patrick M. McKinney

Well, we've thrown out a couple of numbers out there that -- for example, the Gilliland 11HB where without ethane is about 24% liquids, and with ethane, it would be about 45%. And that's -- and that cut is based on gas samples at the wellhead. We're just going to have to go through and look at the different areas to really see what they are. And if you're looking at a good chunk of the acreage being up 15% to potentially 30%, that's a number that'll be incorporated in our proved reserves when we look at things. But at the end of the day, you're going to really go with what you're yielding at the plant to go back to the wells. So I don't think it's going to happen all at once. But as we continue to get higher liquids concentrations, obviously, that's going to move that needle for all the wells out there.

Operator

Our next question comes from Neal Dingmann from SunTrust.

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

Pat, just a couple of things. One, obviously, now the "Super Fracs" and with the pads, obviously, the efficiencies continue to improve. I'm just wondering now when you see sort of well costs going forward, how are you and Tom projecting that, I guess, both as it factors in with improved efficiencies just with the pads and then just with service costs coming down?

Patrick M. McKinney

Well, Neal, this is Pat. I think as Tom alluded to, even when we get into 2013, we're still on a HBP-type program out there where we're looking at drilling -- we may optimize pad locations to get multiple units, but we're still looking at drilling, predominantly, single wells on a unit. And so we're not going to get that total efficiency we'd like to get here at least probably through '13. So the 6.2 million to 6.4 million that we've got in there really still represents a cost of kind of how we're doing business today. I've -- we've talked numerous times on these calls. If we can get to the point where we can go and place a rig on a pad side and get multiple zones drilled, multiple wells drilled in a unit, then we, like other operators, are able to do that, you should see a 15% to 25% reduction in your well costs. So today, when you look at that 6.2 million to 6.4 million, as we've mentioned, we've seen -- well, we were very pleased with the rates we've got from our high-pressure pumping company and our drilling company. And right now, we're plowing most of those savings back into the wells by putting, obviously, longer laterals and more sand in the ground. So this is a placeholder that we've got for capital costs for the Marcellus and Upper Devonian going forward, and our goal will be to try to take that number down.

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

Okay. And then, Pat, you and Tom mentioned this, I just -- if you just refresh me as far as the on the cryo and the processing now, when you look -- I guess, as you kind of go into your production again next year based on the huge ramp that you're all having, are you set now for processing and gathering and the takeaway as far as capacity next year, or will there be a little bit of a lag there because of that?

Thomas C. Stabley

Where we are in the processing right now is we have the 90 million of capacity. That is all reserved for Rex. What we've talked about and what MarkWest have discussed is a fourth quarter incremental commitment from Rex for 100 million a day. So that 100 million will be available to Rex in the fourth quarter. As we lay out the budget in the program for 2013, I think we'll have a better sense of at what point that 90 million gets build up and if there's going be a lag between the 90 million and the start-up of the next 100 million.

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

Got it. And then just last question. Ron was kind of alluding to this. Obviously, with all the chatter now going on after Chesapeake, but especially after the recent results last night on the Utica, Tom, just wondering now, would you wait, I guess, to see couple of these well results and think about, at that point, kind of rescheduling as far as budget process, and how quickly if you'd add another rig or that sort of thing around your Warrior project -- Prospect, either that or the south part of it?

Thomas C. Stabley

Well, I think we're going to put together our 2013 program here over the next several months. We've got the one rig under contract right now, and we've said we have a 2-year deal on that contract. So we're -- that rig is committed to the Ohio Utica side. We've got the -- up to second rig that's committed to Butler. And I think as we see the results in Carroll and we continue to get more comfortable with the results that are occurring in the southern portion of the play, then we'll make that decision. I think the most important thing to talk about, though, is the balance sheet. I mean, the balance sheet, we talked about with $200 million of liquidity available, gives us the flexibility if we want to bring in a second rig. So that's kind of the key for Rex. If we want to accelerate or be inquisitive on additional acreage, we've got the balance sheet to do that. So we'll continue to assess that and make those decisions as the rest of the year plays out.

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

Great answer, Tom. I think you're sitting right on the heart of it.

Operator

Our next question comes from Ray Deacon from Brean Murray.

Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division

Pat, I was wondering if northwestern Butler proves to be significantly better in terms of economics, do you have much capital to commit to kind of block up the acreage? And what would the transportation system look like there?

Patrick M. McKinney

Well, I'll let Tom talk about the acreage position. But I can tell you, as far as the infrastructure, one of the things that I think really needs to be stressed is with MarkWest as our partner now, they're responsible for getting the gathering to the wells and being able to get the takeaway that Tom mentioned of 90 million now and then potentially another 100 million as you get into the end of '13 and into '14. So I have extreme confidence that anywhere that we want to go on our acreage, they'll be able to get there and stay in front of us, and we'll be able to go and go on whatever pace that we desire.

Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division

Got it. Got it.

Thomas C. Stabley

Yes. As far as the acreage goes, again, we are continuing to pick up small amounts of acreage. But the ability to go in and pick up 5,000 or 10,000 acres in those areas are -- that's really not available. We predominantly got shale to the north and west of us and then range a little bit to the southwest of us. So from that perspective, I think the acreage we have is primarily the most amount we're going to get.

Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division

Okay, got it, yes. And just one more question on -- what do we -- what do you expect total acreage purchases for the year? And you talked about Carroll County still wanting to add their -- I guess you said you're actively leasing in Carroll County. I guess, where do you think you could get to by the end of the year?

Thomas C. Stabley

Yes. What we said about Ohio is we're currently at about 18,500 acres. And between Warrior South and Warrior North, we'd like to get that to about 20,000 by the end of the year. So that's a number we're reasonably comfortable with putting out there. And then as far as Butler and Westmoreland go, again, we're -- we've consistently picked up about 1,000 to 2,000 acres a quarter, and that's kind of a pace that we're comfortable with.

Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division

Okay, got it. And I guess any -- what are your discussions like with Williams in terms of resuming activity in Westmoreland? I guess, what kind of gas price would you get -- would it take for you to start looking at that?

Thomas C. Stabley

Well, I think we're in the stages now of discussing that for 2013. I would just say as a reminder, we have currently, I believe, it's 9 wells that have been drilled and not completed in Westmoreland County. And I think it's safe to say with the results that we're seeing and the increased improvement in EURs, that it would be Rex's opinion to probably get in there and try and frac a few more of those to see if we can continue to improve that.

Operator

Our next question comes from Mike Scialla from Stifel, Nicolaus.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Are you guys really going to make us wait until third quarter call to hear rates on the Brace well?

Thomas C. Stabley

Well, the well is going to be put into service, as we said, sometime in September. We typically like to have a good 30-day rate as oppose to an IP rate. That's been Rex's track record. So we'll take a look at what we have. And for right now, that's the timing we're going to give.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

All right. You mentioned the 9 wells that aren't completed in Westmoreland. What is the -- is there a backlog now in Butler, or you had a kind of a steady state with the Bluestone coming on?

Patrick M. McKinney

Well, as we've said, our projected year-end inventory wells drilled but not completed in Butler is at 18. And we feel that MarkWest can meet any kind of schedule that we want, if we want to go and accelerate completions of those. But again, as Tom mentioned, we're really trying to be fiscally responsible with our capital and, again, looking at gas prices. And once we see where they're going to end up and once we go through the budget process, we'll go and make the call for how many of those that we're going to frac as we get into next year with our -- with next year's planned productivity. But I think the good thing is whatever pace that we want to go, I think Tom and I both have full confidence that MarkWest can stay ahead of us. So whatever pace we want to go, I think we can count on them to be there and put the wells into sales.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

So would you then anticipate that 18 number coming down sometime next year, or is that kind of a good run rate?

Thomas C. Stabley

Well, again, we're putting the budget together as we speak, and we'll have some clarity on that when we put out the 2013 numbers.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay. The -- I think you had talked about your typical Butler County well of 5 Bcf curve that you'd been using was -- had a reserve life of 50 years. Is that about the same for the "Super Frac", that 8 Bcf curve that you showed in your presentation?

Patrick M. McKinney

Well, Mike, it's interesting that you asked the question because we did go out and really do look at that and focus on that. I can tell you the one thing that I wanted to make the point and hope we're clear on is that approximate 8 Bcf type curve that we've got was done at $2.85 gas price. So -- and that's assuming what -- if you look at the strip now and year-to-date, that's what the price is estimated to be at year end when we run our proved reserves. So we think it's very important to match that up. I mean, if you use a higher price, then that type curve goes up. So even though we had initially talked about the Drushel being 8.8, we wanted to take some care and make sure that we portray that type curve of approximately 8 and what we think we're going to put reserves at, at the end of the year, and the same for the 5.3 type curve. Obviously, that is going to move around with prices well, too. So you can argue that may even go down somewhat. So the Delta would probably be even more.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

So the 8.8 went to 8. Primarily based on price, you lost some sort of tail reserves there, is that...

Patrick M. McKinney

Yes. And if you look at the average life, I can tell you that we're definitely way under 50 years out there. We average more like 35 years on our PDP and roughly 40 years on the PUD at projected kind of pricing that we're using.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay. So that 8 Bcf is sub-50 years then?

Patrick M. McKinney

Absolutely.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Great, okay. And then last one. I remember -- I probably just missed it. But the Behm I remember you talking about, but I didn't know it was a "Super Frac" well until this release. Is that the first time you had indicated that? And I guess I'm wondering, do you have -- go ahead.

Patrick M. McKinney

No, we had talked about other wells out there, and I don't think we named the Behm per se as one to go and take a look at. So those are the 2 longest that have been out there. We've got a third one that's still at about 260 days of production that we'll be able to talk about at some point, and it was a different type of job that was run out there. It was a Talarico 11H. And so in subsequent calls, we'll be able to give color on that well and how it was completed. And again, as we've mentioned, even with the Carsons, we experimented out there with different sand concentrations and different cluster spacings to try to find the optimal and come up with what the optimal job design it's going to be.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Yes. That's where I was heading. I just wonder if there were others that you had done some experimentation on that you hadn't -- that had some longer history, I guess. So I appreciate that.

Operator

Our next question comes from Jeff Hayden from KLR Group.

Jeffrey Hayden

Guys, I guess starting with the Utica, with that big Gulfport rate, they had pretty long lateral on that one. I think you guys did about 4,000-foot lateral on the Brace. Any thinking of going longer on some of those future wells?

Patrick M. McKinney

Jeff, a lot of it just depends on how you can fit the wells into your acreage. If you've got acreage that allows you to go longer, I think some companies are looking at doing that. For us, with our job designs for the completions, we feel very comfortable in a 3,500-, 3,800-foot to 5,000-foot lateral range is something that we feel we can get a good look at what the well is going to do. So I think most of the longer laterals as you've seen are driven more by -- at least speaking for what we've seen at Chesapeake to based on acreage consideration, it's more than geology or reservoir engineering today.

Jeffrey Hayden

All right. And then I'm hearing some guys in your neck of the woods kind of around the Butler County area, some of the neighboring counties to that are looking around at the Hamilton Group as far as putting some laterals in there. Are you guys evaluating any test to that formation?

Patrick M. McKinney

We're looking at all the intervals, Jeff, when we go through and drill a well. And so we -- I don't think we're in position to talk about any other intervals right now. But our technical team is taking a look and we're going to look at really what else is out there. The -- in Butler, the Hamilton shale really kind of sits on top of the Marcellus, and we'd probably get some contribution in some of our fracs today. But we haven't really talked about using that as a target zone.

Jeffrey Hayden

All right. And then just kind of taking a look at the Burgh well. Maybe I had it incorrectly in my notes somewhere. Was that -- was the Burgh originally supposed to be a Rhinestreet test?

Patrick M. McKinney

Jeff, I believe it was, and what we decided to do is change that to an Upper Devonian Burkett test. And we're going to test the Rhinestreet on a legacy vertical well, just to get an indication of what kind of the gas concentration is. And also, being a little bit shallower, we want to make sure that we get good pressure information from the zone to make sure that we have the appropriate frac job design on it.

Jeffrey Hayden

Okay. So it's just -- I mean, any -- it sounds like no read-through other than it's just maybe a little safer, the deeper zone, that far out west?

Patrick M. McKinney

I think that's a pretty good read on it.

Operator

Our next question comes from Phillip Jungwirth from BMO Capital Markets.

Phillip Jungwirth - BMO Capital Markets U.S.

Looks like you're planning to place in service 3 fewer wells in Butler County in 2012 than you previously expected, but you're still able to raise production guidance. Can we just attribute the higher guidance on fewer wells being turned in line to better-than-expected well performance that you're seeing?

Patrick M. McKinney

Sure. I think that's a good read-through.

Phillip Jungwirth - BMO Capital Markets U.S.

Okay. And then second, on the LOE guidance. You're able to take that down for the second quarter in a row. Is there the -- is there any potential that you'd be able to reduce that $1.50 an M number that you used in your Butler County economics for LOE-gathering processing, given the cost savings that you're seeing?

Patrick M. McKinney

Well, we're real pleased with our LOE trends that we're seeing in Butler. And obviously, increased rates help that number, that metric a lot.

Thomas C. Stabley

Yes. Beyond that, I think just the scale that we're seeing in the production results are driving that number down. So I don't know that we're in a position today to predict any further changes to that.

Phillip Jungwirth - BMO Capital Markets U.S.

Okay. And then last, are you guys looking at this southern Illinois play at all that's gotten some press lately around certain companies leasing in that area, just given your legacy position?

Thomas C. Stabley

Well, again, as Patrick mentioned, we have about 20,000 acres in the basin. Our geology staff is in there taking a look at a lot of these different activities in the area. We're doing some testing on some different things, and we'll keep the market up to date.

Operator

I show no further questions at this time and would like to turn the conference back to Mr. Tom Stabley for our closing remarks.

Thomas C. Stabley

Yes. Thank you. I just want to say thanks for everyone who participated in Rex Energy's Second Quarter Conference Call, and we look forward to seeing you on our third quarter call. Thank you.

Operator

Ladies and gentlemen, thank you for your participation in today's conference. This does conclude the program, and you may all disconnect at this time.

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Source: Rex Energy Management Discusses Q2 2012 Results - Earnings Call Transcript
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