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Executives

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

Patrick M. McKinney - President and Chief Operating Officer

Analysts

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

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

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

Phillip Jungwirth - BMO Capital Markets U.S.

Unknown Analyst -

Jeffrey P. Hayden - Rodman & Renshaw, LLC, Research Division

Rex Energy (REXX) Q3 2011 Earnings Call November 2, 2011 10:00 AM ET

Operator

Good morning, ladies and gentlemen, and welcome to Rex Energy Corporation's conference call to discuss the company's third quarter 2011 financial results. [Operator Instructions] I would now like to introduce Tom Stabley, Chief Executive Officer of Rex Energy.

Thomas C. Stabley

Good morning, and thank you for joining us for the Rex Energy Third Quarter 2011 Financial and Operational Update Call. With me on the call today is our President and Chief Operating Officer, Patrick McKinney. We hope you've had time to review yesterday's 2011 third quarter operational and financial release.

Today's discussions will include forward-looking information and reference non-GAAP financial measures. You should refer to the disclosures in our 2010 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.

Looking at Slide 4. We have a summary of highlights for the third quarter. Production for the third quarter came in at 43.8 million cubic feet equivalent per day, 4% above the high end of our previous issued guidance of 42 million cubic feet equivalent per day. The beat was in combination of our recent Marcellus wells on the Behm pad in Butler County and continued strong performance from our non-operating Marcellus wells in Westmoreland County. With our 24% production growth over the second quarter, Rex has now had 4 consecutive quarters of double-digit growth and has reaffirmed its full year guidance of 88% year-over-year production growth, which is at the midpoint of our current guidance year. In Butler County, we have also completed our first horizontal Utica Shale test well, the Cheeseman #1H. The well flowed at a 24-hour test rate of 9.2 million cubic feet of dry gas per day. The well is currently shut in and is expected to be placed in service in January of 2012. Patrick will give more operational information on the Cheeseman later in the presentation.

Also in Butler County, Keystone Midstream's permit for our second cryogenic processing plant, Bluestone, is in the final stages of permitting and is expected to be commissioned in May of 2012. Keystone Midstream has also received the permit for the Voll field compressor station. With the additional field compression, the Sarsen Plant will be capable of processing its full inlet capacity of 40 million cubic feet per day. Commissioning the Voll compressor station is expected in January of 2012.

In Centre County, Williams has completed the 4-well Resource Recovery pad #3. Two of the 4 wells placed in service had a 5-day average flow rate of 6 million cubic feet per day each and 5.7 million cubic feet per day each over a 15-day period. We are very pleased with the early production rate and improved performance of these 2 wells compared to our first wells in these area.

The additional 2 Resource Recovery wells have been placed into sales, and an update of their production will be available in the company's next operational update.

Finally, in our large field ASP project in Illinois, we are continuing to see positive results from our ASP project in the Middaugh Unit. We are now in the process of working with our third-party engineers, Netherland, Sewell and Associates, to assess proved reserve potential based on current information from the pilot area. More information on the ASP project will be given later in the presentation.

Moving to Slide 5, there are some bullet points I would like to highlight. As stated earlier, our average daily production increased 24% over the second quarter with oil and natural gas liquids accounting for 36% of the total production. Lease operating expenses for the quarter were $9.1 million, which is an increase of 11% over the second quarter. Looking at this on a per Mcfe basis, it was approximately $2.26 per Mcfe, which is 11% lower than the second quarter. Adjusted net income was $6.4 million or $0.14 a share. This is $2.5 million or $0.05 per share above the second quarter.

And EBITDAX, a non-GAAP measure, was approximately $18.8 million for the third quarter or $0.42 per share, which is 41% above the second quarter. Increase in the EBITDAX is attributable to our increased production and lower expected related G&A costs.

For a detailed reconciliation of these non-GAAP measures to GAAP net income, please see the appendix at the end of this presentation.

On Slide 6, we have our current hedging summary, we continue to hedge our production as the market allows and currently have 92% of our 2012 crude oil production hedged at an average floor price of approximately $68 and $111 ceiling and 48% of our 2012 natural gas production hedged with an average floor price of just over $5. Both percentage estimates are based on the midpoint of our 2011 exit rate guidance of 51.8 million cubic feet equivalent per day. As opportunities become available, the company will continue to add to its existing hedge position in the future.

For more detailed information on our hedging position, please see the appendix at the end of this presentation.

Moving to Slide 7, we would like provide our fourth quarter 2011 and full year guidance. We expect fourth quarter average daily production to be between 46 million and 50 million cubic feet equivalent per day and reiterated our previous full-year production guidance of 37 million to 40.4 million cubic feet equivalent per day. We're increasing our exit rate from a previous range of 47 million to 53.5 million cubic feet equivalent per day to a range of 48.5 million to 55 million cubic feet per day. This increase is attributable to the continued strong performance of our non-operating wells and additional capacity in Westmoreland County.

Fourth quarter lease operating expenses are expected to be the range of $9.3 to $9.6 million with full year estimates within our previous issued guidance of $31 million to $34 million. Cash G&A for the fourth quarter is expected to be in the range of $5.6 to $6 million. We are lowering the full year cash G&A guidance as previously provided to a range from $24 million to $25 million to a range of $23.5 million to $24.5 million.

Finally, the company is providing initial operating CapEx and production guidance for 2012. Initial operating capital for 2012 is expected to be in a range of $175 million to $190 million and should provide the company estimated annual production growth of 70% to 80% year-over-year. Details of the 2012 capital budget and production guidance will be provided in December.

Moving to Slide 8. The company's capital expenditure budget is being increased to $270 million, up from previous released guidance of $235.6 million. The increase is largely due to activities in the company's Butler Operated Area with the drilling of wells with longer laterals, testing and evaluating different fracture stimulation designs and methods, and also increased costs experienced on our first Utica Shale well. In addition, the company has begun title and pad preparation work for 2012 drilling program and will incur additional capital expenditures for leasing in our Warrior Prospect in Carroll County, Ohio. Funding for the increase will come from the company's existing line of credit and cash flows from operations. The next redetermination for the company's line of credit is currently scheduled for December of this year. Details of the CapEx breakdown are available in the company's corporate presentation on its website.

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

Patrick M. McKinney

Thanks, Tom. Looking at Slide 9. I'd like to give an update on our Butler County, Pennsylvania operated area. We now have an acreage position of 65,000 gross, 44,500 net acres in the area. As previously released, we've fracture simulated and completed our first Upper Devonian well, the Gilliland #11-HB. This well was drilled to a lateral length of 2,700 feet and had a 5-day flow rate of approximately 3.1 million cubic feet equivalent per day of wet gas. The gas was similar in composition to the gas were producing in the same area from the Marcellus Shale. Given the lateral length and production rates, the well is exhibiting similar production characteristics as our Marcellus Shale wells.

When the well is put into sales, which should be sometime in the first quarter 2012, we get a better picture of the decline curve and estimated ultimate recovery potential of the well. We feel encouraged by these results and expect the drilling to complete additional Upper Devonian wells during our 2012 drilling program. We've also drilled and completed our first Utica Shale well in Butler County, the Cheeseman #1H. The well has a lateral length of approximately 3,550 feet and was completed with a 12-stage frac. The well had a stabilized 24-hour test rate of 9.2 million cubic feet per day of dry gas. We expect the well to go into sale in January of 2012, after pipeline construction is scheduled to be completed.

As with our Upper Devonian well, we're waiting to place the well into sales to determine the decline rate and estimated ultimate recovery potential of the well. We see the current results as positive and are expecting to drill and complete additional Utica Shale wells in Butler County during our 2012 drilling program.

Just one final comment on our asset base in Butler County. We now have identified the prospect of 3 significant producing horizons on our acreage. Our recent results from the Behm wells are driving Marcellus EURs to 5 Bcfe. The Burkett/Upper Devonian test rate coupled with well controlled steam from our Marcellus drilling through the interval to date gives us confidence that this zone is pervasive throughout our acreage position. Additionally, our Utica Shale dry gas discovery gives us additional options on blending with our wet gas to increase plant throughput that could add a tremendous amount of flex ability on production timing and growth. We truly feel we have world-class asset it.

On Slide 10, I'd like to give a little bit more color on our progress regarding our Midstream infrastructure in Butler County. With the quality of our asset base in Butler County, we feel strongly that we need to protect our ability to sell the product. We have secured a firm transportation contract with BP for a total of 85 million cubic feet per day. We will receive an initial 25 million cubic feet per day of transportation in March 2012, with the remaining 60 million cubic feet per day available in January 2013. We feel that this will ensure our ability to grow production in the area and the firm transportation agreement lines up well with our plans to add a second cryogenic plant in 2012.

As Tom stated earlier, the permits for our 50 million cubic feet a day Bluestone Plant are in the final stages, and we received the permit approval for our Voll compressor station. We expect the permits for the Bluestone Plant to be issued by December of this year. Construction on the Voll compressor site will be complete, and production should be flowing through the compressors in January 2012.

We expect the Bluestone Plant to be commissioned in May of 2012. With the recent promulgation of Pennsylvania DEP's air permit aggregation policy and Governor Corbett's new proposal to the state Oil and Gas Act, we feel that we are entering a period of increased predictability in regard to future regulatory environment in the Commonwealth. We're in the process of determining the location for a third processing plant and are negotiating other firm transportation to ensure our ability to grow and expand our operations in the area.

Moving to Slide 12, we have recurrent drilling completion schedule for our Butler County area. We've transitioned to a 1-rig program for the remainder of the year. The rig is currently drilling on the pallet drill side, where it will drill one well. This will be the last well in our 2011 drilling program.

Year-to-date, we drilled 29 gross, 19.7 net wells, with 20 gross, 13.4 net wells drilled and awaiting completion. We have completed and placed into service 16 gross, 11.2 net wells with another 4 gross, 2.8 net wells completed and awaiting pipeline construction. We feel that our inventory of 18 wells drilled and awaiting completion at year end will enable us to fracture stimulate wells as needed not only to keep the Sarsen Plant at full capacity but additionally fill the Bluestone Plant in a timely manner.

We are evaluating our options for 2012 and will announce more information on our 2012 drilling program at a later date.

Transitioning to our non-operated area on Slide 12, there are some points I'd like to highlight. We have maintained our leasehold in the area with our current acreage position of approximately 43,000 gross, 16,600 net acres. Our operating partner, Williams, is working to expand capacity in the Westmoreland County area. With the additional capacity expected to be available in the fourth quarter of this year, we anticipate having a total of 79 million cubic feet per day of pipeline capacity by the end of the year. This will allow curtailed wells to flow at their potential as well as new wells to go into sales at higher rates.

In the Centre and Clearfield County area, Williams has recently placed the 4-well Resource Recovery pad into sales. Two of the 4 wells were placed into the sales with an average 5-day rate of 6 million cubic feet per day and an average 15-day rate of 5.7 million cubic feet per day. The remaining 2 wells have been recently placed into sales, and those results will be announced at a later date.

The bottom line is that Williams has done a great job in getting wells drilled and completed this year. They're increasing the IP rates in new wells, which results in increased EURs, and have expanded their takeaway capacity to drive production growth as we head into 2012.

On Slide 13, we have our drilling completion schedule for our non-operated area. Williams has transitioned to 1-rig program for the remainder of the year and the rig is currently drilling the first well in our 2-well Talarico [ph] pad. We expect Williams to continue with a 1-rig drilling program in the area for 2012. In Westmoreland County, Williams has drilled 20 gross, 8 net wells, placed 12 gross, 4.8 net wells into service and has 10 gross, 4 net wells drilled and awaiting completion. For the remainder of the year, Williams plans to drill 2 wells on the Talarico [ph] pad, fracture stimulate 12 gross, 4.8 net wells and place 9 gross, 3.6 wells into service.

At the end of the year, Williams expects to have 2 gross, 0.8 net wells drilled and awaiting completion. In Clearfield and Centre counties, Williams has drilled 4 gross, 1.6 net wells year-to-date and placed 5 gross, 2 net wells into service. Williams is not planning any further development in the Clearfield Centre County area in 2011.

On Slide 14, we have our Utica Shale overview. To date, we have a total of approximately 85,300 gross, 58,700 net acres perspective in this area for the Utica Shale. Chesapeake Energy has recently disclosed well results for 4 wells in their Utica Shale program, 3 of which are in close proximity to our Carroll County, Ohio acreage position. Locations and production rates for these wells are shown on the graph. As more production rates are disclosed, we feel confident that our Butler County acreage will be in the dry gas window and that all of our acreage in Carroll County, Ohio will be at ground 0 for the liquids rich condensate window.

Moving to Slide 15, we have more detailed information on our Warrior Prospect in Carroll County, Ohio. We have closed on the 11,000 acres previously announced and are targeting 15,000 acres leasehold in the area by the end of this year. This should result in between 80 to 100 net drilling locations in the quarter play. We've also secured 15 million cubic feet a day of firm capacity in the play from Dominion after a Natrium processing facility starting December 2012. In the interim, we will have a rental processing at Dominion's Hastings processing plant. This will give Rex the ability to sell wet gas in the Dominion system to get full liquids extraction for our Utica, Ohio program. As we have mentioned previously, we will take delivery our build-to-suit big rig capable of drilling the Utica in both Pennsylvania and Ohio in the second quarter of 2012.

On Slide 16, we have an update our ASP prospect in the Illinois basin. Production from the project has maintained a range between 73 and 82 gross barrels of oil per day over the last 30 days. Oil cut in the entire unit has increased from an initial 1% oil cut to 12%, with 5 of the 6 producers and their patterns showing increased response. Based on production models from the first responding pattern, we believe that we have recovered incremental oil production of 6% of pore volume. Four additional responding patterns are following the same production profile. With these results and other reliable reservoir engineering methods, the pilot performance appears to be in line with our internal estimates, and we are working with our third-party engineering firm, Netherland, Sewell and Associates to determine the level of proved reserves from our ASP project.

We feel confident in these results and are moving forward with our expansion into 58-acre Perkins-Smith area in 2012. We're also preparing to expand into another ASP project area, the 351-acre Delta unit. We anticipate beginning the development of this area in 2012.

Moving to Slide 17, we've completed -- finished completion operations on our Steege 11-33 well and the Shapley 14-25 well. Both of these wells have been determined to noncommercial. As a result, we have expensed the cost of these wells and have also written down the remaining asset value of 3 wells drilled prior to these wells as these wells were also determined to be noncommercial. With our large inventory of liquids rich prospects and projects with higher rates of return, we're analyzing strategic alternatives for this area. We are considering possible joint ventures with other operators or a possible sale of the approximately 40,000 net acres that are currently leased.

With that, I would like to open the phone lines for question-and-answer.

Question-and-Answer Session

Operator

[Operator Instructions] And our first question comes from Jeff Hayden of Rodman.

Jeffrey P. Hayden - Rodman & Renshaw, LLC, Research Division

Tom, I'm wondering in the in as much detail as you're wanting to give, what kind of drilling program or how many rigs do you kind of assuming in that $175 million to $190 million preliminary budget?

Thomas C. Stabley

Obviously, we've given the guidance on what Williams' program is for next year. Their plan is to want to run a 1-rig program in that Westmoreland-Clearfield area. On the Rex side, we have the one existing rig that we're currently running, which is the smaller double rig, and then we're taking delivery of the larger triple rig in the second quarter. So we'd have a 2-rig program in both the Butler and Ohio Utica unit areas.

Jeffrey P. Hayden - Rodman & Renshaw, LLC, Research Division

Okay, great. And then just one little housekeeping item. Looking at the interest expense in the quarter, just looked a lighter than I was expecting. Was there any capitalized interest?

Thomas C. Stabley

Yes, there was a portion of capitalized interest related to the Marcellus wells.

Jeffrey P. Hayden - Rodman & Renshaw, LLC, Research Division

Okay. Can you quantify that?

Thomas C. Stabley

About $400,000.

Operator

And our next question comes from Neal Dingmann of SunTrust.

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

A couple of questions, mostly just on takeaway for Pat or Tom. Just first on looking at Butler County, you did mention in there a couple of things. Not to get too far ahead but just want to know around more on the Utica, on the well that you drilled, kind of give plans for next year. Do you have anything in that CapEx as far as capacity that will be coming online in that area?

Thomas C. Stabley

We currently are working on -- it's going to be an interruptible contract with National Fuel Gas for the existing Cheeseman well, and then the ultimate goal will be to bring that gas out of that upper area down into the Dominion line and even possibly blend it with some of the wet gas in the Marcellus to help us get some incremental production out of those plants.

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

Okay. And then not to get too far ahead after -- in the Marcellus, after the Bluestone, are you looking at plans already for another plant beyond that one that likely will come on in May?

Thomas C. Stabley

Plant 3, we currently have the permits submitted or in the process of picking the final location to where that plant should be located.

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

And so far, just in your Butler area, approximately, I mean, how many well locations do you have these days?

Patrick M. McKinney

Well, Neal, we've reasons stated in kind of our Forward Township area, we have about 385 Marcellus locations. So we feel the Upper Devonian/Burkett is pervasive to that same acreage, and then now we've got the Utica through it. So I guess you can take the 385 and multiply it by 3, that we've identified in units that we've got currently existing.

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

Wow, okay. And then just last one. In Carroll, now especially if you get that full 15,000 acres, Pat or Tom, what sort of the plan takeaway or where will you go with that production next year?

Thomas C. Stabley

Well, the takeaway capacity is the 15 million that we talked about going in the Natrium, and then we're in the final stages right now of negotiations with Dominion of Ohio -- I hope to have that signed here shortly -- where we'll have $15 million of firm transport to get the gas directly in the Natrium. So we think we'll be in a good position for a first mover advantage to be able to drill those wells, frac them and get them right in the line.

Operator

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

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

Can you talk about your well costs now for the Butler County Marcellus wells?

Patrick M. McKinney

Sure, Mike. This is Pat. As we've gone through our process of optimizing these wells, we've taken our average lateral length from about 3,400 feet to over 4,000 feet. That's increased our stage count from 10 stages to 12 to 13 stages. We're also additionally getting about 30% more sand in each of the stages that we pump. So that 47 that we've been using obviously is going to go up, and we've talked about being in the low to mid-5s as far as what development cost is going to be going forward. We'll publish that in December when we talk about our capital budget and also show the returns with that. But we feel that the incremental well cost has been accretive obviously on the economics with the higher EURs.

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

And the capital budget increase you mentioned in your release was primarily due to the increase in the well cost. Was it strictly due to the change in design or is there some service cost inflation in there as well?

Patrick M. McKinney

That's a good question, Mike. I would tell you that for the most part, our cost structure is still controllable, so most of the increases were controllable costs with design, but we also have some prep work for 2012 in there. There were some additional acreage and some additional midstream in there. But I would still say that our service costs because of our long-term contract with Union Drilling and Frac Tech that they've been controllable, that we've driven most of the cost increase through our increased job designs.

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

And I know you want to wait till December to finally talk about it in December when you formalize your budget more, but can you give us any sense on what the Utica might cost in your northern Butler acreage. I mean, is this -- do you have to use the high horsepower to complete these wells or is $6.5 million range of cost in the ballpark?

Patrick M. McKinney

Yes, Mike. I think there's 2 things, and you hit on one of them. We're still looking at between $6.5 million and $7.5 million for our Pennsylvania Utica and 2 key things that the need to work through is obviously the higher horsepower. If we can keep this frac jobs below 10,000 psi, that puts us in a pricing realm that's similar to the Marcellus. And secondly, we ran an intermediate string to get through the salt section. If we can go in and avoid having to run that intermediate string, I think then we can be able on the lower end of the cost side. Both of those things we're working on as we go forward in the program.

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

And then last one for me. Looking at -- you'd mentioned the DJ, you're looking at strategic alternatives. Any thoughts on your any other assets that might be noncore, not up Marcellus core at this point, any activity there and marketing that or your midstream assets?

Thomas C. Stabley

We continue to look at the midstream assets and also the dry gas component or a portion thereof it. Obviously, we have 2 pretty good candidates in Sumitomo and Williams to help us with that if we want. In addition to that, we've obviously got the Utica potential for a JV, and then we've always said we look at the high yield bond markets as we move into 2012. So I think for Rex, we've got a lot of optionality in that the near term. We've got the increase in the borrowing base, so we'll continue to look at each one of those as we move forward.

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

Nothing that you're actively marketing today, though?

Thomas C. Stabley

Just that we're actively looking at the Niobrara acreage.

Operator

Our next question comes from Don Crist of Johnson Rice.

Unknown Analyst -

It's John. Question is just a follow-up on your last point. Have all formally opened up a data room? Is there an expected timeframe for the Niobrara process to work itself through?

Patrick M. McKinney

Ron, we haven't formally opened up an external marketing process on. We've had a number of folks come in that we've done kind of one-off, but we're in the process of evaluating what exactly we want to do as far as a full-blown marketing program out there.

Unknown Analyst -

Okay. And looking at your 2012 capital budget obviously bearing back the overall number, quite a bit concentrating in your Marcellus, Utica, ASP areas. But when you look at that production growth of the 70% to 80%, how are you guys looking at that on a production mix standpoint given the startup of drilling in the Utica? The Marcellus has been driving the gas proportion increase quite a bit. Is that going to continue through 2012 or how should we look at just the mix?

Thomas C. Stabley

Yes, the mix will continue obviously in the first and second quarters. We've got the larger triple rig scheduled to arrive in the second quarter. So any of those wells that are drilled in the Utica, the majority of that production is going to be seen in the second quarter, at which time we should start to see some relief on that mix. But for the most part, the trend that was exhibited in 2011 would probably be very similar to what you'll see in '12.

Unknown Analyst -

Okay. And in the Utica, I know the Cheeseman well in Butler County was drilled where it was just to test the potential for gas and/or liquids. Geologically, as you move across your 44,000-acre position there in Butler County, when you look at it as a dry gas play, are there any differences as you move from the Cheeseman south and east through your Butler County or do you think the geology should be fairly similar. I'm asking just because you have a stronger initial rate than what we saw out of range. I don't know the comparable laterals or frac stages but trying to get a sense in terms of what you think as you move south and east through that 44,000-acre block?

Patrick M. McKinney

Ron, this is Pat. I mean, I think our geologists feel pretty confident that the section that we saw in the Cheeseman exists pretty much it gets deeper as you go to the Southeast, but it exists throughout a good chunk of our acreage. There's a couple of blind spots that we've got in there, but for the most part, we feel pretty confident that there exists a good chunk of our acreage and obviously some of the well locations we may pick next year to test that are going to be to really kind of firm that up.

Unknown Analyst -

Okay. And then when you look at the Utica in Ohio, thanks for the clarification on the takeaway capacity. I'm assuming that you as well are targeting more the Point Pleasant portion of the Utica. Do you have -- have you been able to get any well control in terms of old logs or anything around your position to point towards the presence of Point Pleasant? And if so, do you have any initial metrics in terms of potential thickness and whatnot?

Patrick M. McKinney

Yes, we haven't disclosed the thickness that we saw in the Cheeseman for both the Utica and Point Pleasant, but we were pleased with what we saw. We've got some 2D through the area and some well-control, and from what we see today, we think that the similar thickness are exhibited through our acreage. But we are targeting landing the lateral to Point Pleasant because that's the part of the zone that has the best porosity and some of the best shows and then frac in and frac up into the Utica, but we're very pleased with what we saw in terms of porosity on this well, and as far as lithology, that the Point Pleasant is definitely carbonated. And the Utica had a lot of carbonate in it as well, too, and had good porosity. So we think that's the key is these plays, having both those benches present, relatively thick and having good porosity.

Unknown Analyst -

Okay. And then one last one. The ASP, it sounds like the results continue to at least meet your estimates, and you've worked with Netherland, Sewell on this project for a number of years now. What do you think that they'll want to see to be able for them to book reserves at year end. Is it just the poor volume recovery that you're seeing here? Or do they want to see that full volume recovery on all of the patterns? You seem to allude that you think you've seen enough. Now I just don't know in your recent conversations if what you've seen so far is enough for them. And then relative to your overall position, the ASP, the Middaugh units of 15 acres, what kind of bookability are we talking about for your total position in that ASP area?

Patrick M. McKinney

Well, first on continuing the trend, I mean, each day that we go on and continue to have a plateau in production gives us more confidence that we're going to continue to take the poor volume recovery up. And the process is really looking at the pilot being able to history match and model its actual performance and model that in future units. And so as we go through the rest of the fourth quarter here, and continue to exhibit this response. It gives us more confidence to be able take the poor volume recoveries up when you model the pilot. In terms of looking at other areas, we can only book proved reserves in separate and distinct sand bodies as we go in and do the same amount of testing, meaning going and getting a core, and doing the core flooding, doing the fluid-to-fluid work in each subsequent sand body and then using the simulation model to go and estimate ultimate recovery in those sand bodies. So when we get to the end of the year, we're only really looking at booking proved reserves in the current sand body that is around the middle pilot and the 2 blocks of the rigs to the east and Perkins-Smith to the west around it.

Unknown Analyst -

Okay. And I guess one thing that is -- is that you now talk about the 300-plus-acre project that you may look to start up next year, a much bigger area. Can you walk through some of the thought process in terms of moving down to that 300-plus-acre area and how the response times may differ?

Patrick M. McKinney

Sure, Ron. We've been asked on as we go and expand the pilot, you want to try and get a higher impact or as much impact as you a can as you go and start the future development. So we've looked at the Delta unit directly south of our current sand body, and I'm going to start the prep work there next year by cutting the core, doing the lab work, doing the simulation modeling and getting that reservoir analyzed and ready to be able to go and start the preflush and try to get most of that work done in '12. So we can look at getting that on and impactful production as soon as possible. We don't know yet what the timing is going to be because we're going to use a simulation modeling to go and get an optimal pattern design down there and injection and recovery profile. So we're still early in that, but I think we can safely say that we want to try to go and pick up some higher impact areas now that we have confidence that this ASP program is going to work.

Operator

Our next question comes from Brian Lively of Tudor, Pickering.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Think about the Bluestone Plant next year and your 2012 production guidance. It seems like you're ramping production through that plant fairly slowly before you get to kind of the peak. What's the, I guess, upside for really expanding and moving these volumes faster?

Thomas C. Stabley

Well, I think what you talked about is we have the inventory of 18 wells available at the end of 2011 and that we would begin frac-ing those wells to the first and second quarters so as to have them ready for the ramp-up of that plant in sometime in May of 2012.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Right, but the capacity of that plant, I mean, what's the assumption right now before you hit full capacity from a supply standpoint?

Patrick M. McKinney

Hey, Brian. This is Pat. As with any plant start up, as we start the commissioning just like we saw in the Sarsen plant in December of last year, you can't slam that plant with a full 50 million a day on Day 1. You have to go in and slowly walk it up, and so it's going to take a month, a month and a half or so to walk that thing up to its capacity. And with any plant startup, you're going to have the shakedown process and different issues with it to bring it to full capacity. So as Tom mentioned, we're going to have what we think is a very sufficient well inventory to fill that plant. That'll be frac-ed by the time it's needing initial volumes to go through the startup. And then as we get through the startup we think we'll going to have ample inventory to go and fill it up. So if you use that a little bit of a month, month and a half to get up to full capacity for May, that's probably going to be a good way to look at it.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And that timing is consistent with the production guidance for next year?

Thomas C. Stabley

Yes, that's correct.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

On the Utica side, the Cheeseman well, since it's dry gas, do you have to run the Utica volumes through the plant or do you sell or do you bypass the plant?

Patrick M. McKinney

No, I mean, you could theoretically take a ride into a dry gas tap into the sales line, but what our plant guys are telling us is they really are excited about the opportunity of having some dry gas to mix, which again will allow them more flexibility and being able to deal with the ethane and perhaps getting better plant yields. We don't have a volume to talk about that they would run through the plant or what any increase in throughput in the plants, but we know it's something that we think it's going to be significant. And we view the Utica as really some of that will go through the existing plants, but a good chunk of it can be directed directly to the Dominion line, tapped and sold without having it go through the plants.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

So if understand, the Utica will actually help you expand the existing capacity on Sarsen and the Bluestone Plant?

Patrick M. McKinney

Yes, that's what they're thinking right now.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. Over on the Ohio acreage, what is your expected split between condensate and NGL even if it's on a yield basis?

Patrick M. McKinney

Well I think the early indications from Aubrey are about 60-40, I think. 60% gas, 40% liquids, but until we see some more results, I mean, we have the same information you guys do.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay, I was looking more for the split of the liquids itself. Is it more weighted to NGLs or more weighted to condensate? That's what...

Patrick M. McKinney

Well, again, we haven't seen anything other than what you guys have seen. So we're just taking the well results kind of at face value that Aubrey has put out there.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

All right. And then last for me. Just on the Niobrara, can you discuss the 2 separate wells, when testing the kind of higher resistivity area, when lower resistivity area, what were your learnings there?

Patrick M. McKinney

We're just going to say that the wells were deemed noncommercial. We didn't say they were dry. We said they were noncommercial. And so if you want to go into the data room, you can see more information.

Operator

[Operator Instructions] Our next question comes from Carl Rhodes [ph] of RBC.

Unknown Analyst -

Can you talk a little bit about your thought process on the siding whether it will go with your Carroll County acreage alone or take on a partner? Are you guys wanting to see some of your own results or you could have a deal before that?

Thomas C. Stabley

Yes, I mean, we're -- as we mentioned, we're looking at a number of different alternatives. Some of them will depend on the amount of acreage we're able to get in and around our area. But I think getting some additional well results would be important before we make any type of decision. We've obviously done it both ways in Westmoreland and Butler with Sumitomo. So I think we're going to wait to see some additional data points.

Operator

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

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

I just want to follow up on the Bluestone plant. You said it's in the final stages of getting permit. Is that in a public comment period our where is it?

Thomas C. Stabley

Well, I think what we're in a position to say is that we're in the final stages right now, and our hope is that we'll have that permit by the end of the year under the current plans.

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

And are you dealing with the EPA at this point or the state, or can you say anything?

Thomas C. Stabley

The local issues have been all taken care off. We're in the final stages with the state DEP, so the permit will come from the state DEP.

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

Okay. And then I just wanted to follow up on the Niobrara acreage. Any additional commitments you have there to hold the 40,000 net acres together?

Thomas C. Stabley

We don't. For the most part, there are minimal expiries that will take place in 2012.

Operator

[Operator Instructions] And our next question comes from Phillip Jungwirth of BMO Capital Markets.

Phillip Jungwirth - BMO Capital Markets U.S.

Based on the 2 production tests you have from the Butler County, Utica and Upper Devonian, which target are you more encouraged about and which will receive more capital in 2012?

Patrick M. McKinney

Well, Philip, this is Pat. We're still going to hold out until December to really lay out our capital plan, but we feel we've got a lot of flexibility now. In most of our acreage out there that we're looking to hold next year, we have all depths, all rights, and so we can hold it with a Upper Devonian/Burkett test or hold it with a Utica test or hold it with a Marcellus test. So we're currently working on a development program that we can go through and look through different areas of the field that fit in that expiry plan and drill the Upper Devonian well to go in and test it in a different part of the field, and the same for the Utica. But to be sure, most of our development next year will still be with our Marcellus program as we look to fill the second plant up. And then also, we're starting to get line inside of the third plant. So we'll have more color on that in December. Sorry, I can't give you more right now.

Phillip Jungwirth - BMO Capital Markets U.S.

Okay and then in the Ohio Utica, is the additional 4,000 net acres you're looking to acquire, is that in the revised capital budget or is that being incremental? And then are you sticking to Carroll County with your leasing efforts?

Thomas C. Stabley

A portion of that incremental 4,000 acres is in that revised capital, and the answer to the second question is yes. We're saying inside of Carroll County. We're saying outside the Warrior Prospect and really trying to build out of those additional units to increase the number of laterals that Pat talked about earlier.

Phillip Jungwirth - BMO Capital Markets U.S.

Okay and then can you say how much Ohio Utica production is in the '12 guidance or how many wells that you're looking to drill there? Or is that in December time also?

Thomas C. Stabley

No, that'll be in December before we discuss that.

Phillip Jungwirth - BMO Capital Markets U.S.

Okay. And then last, how does the 385 Butler County location number change if you assume the longer laterals and the new well economics?

Patrick M. McKinney

Well, the 385 was based on our concentrated really Forward Township area, which is only about 20,000 out of our 43,000 net acres. So we haven't really gone beyond that and looked at different number of units but the 385 really exists in existing units that we've identified. And so most of the lateral lengths have already been kind of laid out. And with most of our units in Pennsylvania, it's going to be tough to get much above 4,500-foot lateral just on how the units are laid out. So as we mentioned, our kind of typical development lateral now for the Marcellus has gone from 3,400 feet to 4,000 feet. And I think if you use that 4,000-foot kind of model going out, that's probably going to be representative of most of our wells. Not to say that some are still going to be shorter, some may be up to 4,500 feet, but on average, our lateral lengths now are going to be about 4,000 feet.

Operator

Thank you. I'm showing no further questions at this time. I'd like to turn the call back to Mr. Stabley for closing remarks.

Thomas C. Stabley

Great. Thank you. And I'd like to thank everyone for participating on Rex Energy's third quarter conference call. And we look forward to seeing you at the end of the fourth quarter. Thank you.

Operator

Ladies and gentlemen, thank you for your participation in today's conference. This concludes the program. You may all now disconnect. Thank you and have a nice day.

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