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Rex Energy (NASDAQ:REXX)

Q1 2012 Earnings Call

May 02, 2012 10:00 am ET

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

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

Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division

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

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

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

Unknown Analyst

Operator

Good morning, ladies and gentlemen, and welcome to the Rex Energy Corporation's conference call to discuss the company's first quarter 2012 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 first quarter 2012 financial and operational update call. With me on the call today is our President and Chief Operating Officer, Patrick McKinney. We've hoped you had the time to review yesterday's 2012 first quarter operational and financial release. Today's discussion will include forward-looking information and reference non-GAAP financial measures. Issued a further disclosure in 2011 Form 10-K and other SEC filings regarding factors that could cause our future results to differ from forward-looking information.

Moving to Slide 2. A reconciliation of non-GAAP financial measures can be found our website and our 8-K filed yesterday with the SEC. We've also included additional information in the presentation materials posted on our website to help you analyze the company's performance.

Moving onto Slide 4. Beginning on Slide 4, we have a summary of highlights for the first quarter. Production for the first quarter came in at 60.7 million cubic feet equivalent per day, which is 1% above the high end of our previously issued guidance of 60 million cubic feet equivalent per day. The beat was a combination of the strong performance from our non-operated Marcellus wells in Westmoreland County, Illinois production related to a mild winter and continued strong performance from our core assets in Butler Operated Area. We remain very encouraged with the performance of the most recent 7 wells in Westmoreland County after their first 120 days, which has exceeded our 4.2 BCF type-curve by over 50%. With our 23% production increase over the fourth quarter, Rex has now had 6 consecutive quarters of double-digit growth.

Also contributing to the strong production performance is the Drushel #3H well in Butler County. This well was completed over a year ago with the company's new "Super Frac" design and was tested along with 2 other wells during our 2011 program utilizing the same technique. The combination of higher sand concentration, reduced cluster spacing has resulted it in an EUR for the well of approximately 8.8 BCFE. We are continuing to test the "Super Frac" design and most recently frac-ed our 2 Carson wells with 4,000-foot laterals using this method. These 2 wells will be placed in the sales with the commissioning of our second jointly-owned cryogenic plant, which is scheduled for the start-up at the end of May.

I'm also pleased to announce that we have closed on our 15,000 acres in the Warrior Prospect in Carroll County, Ohio, and have begun drilling operations on our first well in this area, the Brace #1. Completion operations for this well are currently scheduled for June of this year. In addition to our 15,000 acres in Carroll County, we have now completed acquirement agreement located in the tri-county area of Noble, Guernsey and Belmont Counties. The agreement includes 4,500 gross, 2,800 net acres and will be referred to as the Warrior South Prospect. This will bring our total Ohio Utica acreage up to approximately 17,800 net acres. Our initial commitment under this farm end is to drill and complete 1 horizontal well and commence the drilling of 2 others by November 15. We have adjusted our drilling plan accordingly to allow for 1 of 3 budgeted wells for the Warrior Prospects to be completed in the Warrior South area and the remaining 2 in the Carroll area. This will not change the full-year budget.

In addition to the acreage added in Ohio, we also added 3,300 net acres in Marcellus, including 1,200 in our Butler operated area, with the remainder mostly in Westmoreland Counties. Including our farm end agreement in the Warrior South Prospect, we have added approximately 6,100 net acres in the Appalachian Basin during the quarter. Similar to last year's leasing plan, we will be very opportunistic at adding good quality acreage that is accretive to our existing positions and focus predominantly on liquids opportunities.

In regards to the company's current May borrowing base redetermination, we remain very encouraged with the process and we'll update the market in the next several weeks. Lastly, as previously announced, Rex is actively evaluating potential opportunities to invest its jointly-owned midstream assets in its Niobrara assets. The marketing process for each of these initiatives continue to progress and based on the current status and anticipated timing of the potential transaction, the company expects to provide an update to the market on these planned asset divestitures within the next 2 weeks.

Moving to Slide 5. Moving to Slide 5, there are some points I would like to highlight. As stated earlier, our average daily production increased 23% over the fourth quarter, with oil and NGL accounting for 26% of our production. Lease operating expenses for the quarter, excluding the onetime $2.8 million for the retroactive portion of the new Pennsylvania impact fee or $9.5 million or approximately $1.72 per Mcfe. $1.72 per Mcfe is a 40% reduction in LOE on a per unit basis over the first quarter of 2011. Included in $1.72, we did record approximately 600,000 to begin accruing for the 2012 impact fee, which will be recorded and spread throughout the year as each new well is spud for accounting purposes. We treat this as lease operating expenses.

LOE for the first quarter adjusted for the retroactive impact fee came in below the previous issued guidance, in large part due to the Illinois Basin experiencing a much milder winter. In addition, we've experienced reduced LOEs in our Marcellus shale operations due to increased operating efficiencies and cost reduction measures. We are continuing to look at ways to further reduce LOEs through an active review of all services and contracts through continued further efficiencies. As a result of these savings, the company has adjusted its full-year guidance accordingly seen on Slide 7.

Adjusted net income from continuing operations for the first quarter was $5.3 million or $0.11 per share. This represents a $3.1 million or $0.06 per share above the first quarter of 2011. EBITDAX from continuing operations, a non-GAAP measure, was approximately $21.5 million for the first quarter or $0.44 per share, which is an 8% increase over the fourth quarter. 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 provide our current hedging summary. We currently have 87% of our 2012 crude oil production hedge with an average floor price of $68 and ceilings of $111 and 67% of our 2012 production hedge with an average floor of $4.43. For 2013, we have 81% of our crude oil production hedged with an average floor price of $72.44 and a ceiling of approximately $112 and 87% of our 2013 production hedged with an average floor of $4.39. We recently began the process of hedging additional natural gas production in 2014 and as of today, we have 18% of our current gas production hedged at a floor price of $3.50. All percentage estimates are based on the midpoint of our second quarter 2012 production guidance of 64.5 million cubic feet equivalent per day. As opportunities become available, the company will continue to add to these existing hedge position.

The company is very pleased with this existing hedge book and feels it provides a strong cash flow base to protect its current borrowing base and execute on current and future capital plans. For more details on our hedge position, please see the Appendix at the end of our current corporate presentation.

Moving on to Slide 7, we would like to discuss our second quarter 2012 and full-year guidance. We expect second quarter average production to average between 61 and 66 million cubic feet equivalent per day. For full-year, we are now expect average daily production to be in the range of 67 million and 72 million cubic feet equivalent per day, which is approximately 6% higher than our previous guidance of 63 million to 68 million cubic feet. This increase in production as mentioned earlier, is a result of continued strong performance from both our Butler and Westmoreland Marcellus operations. I think it is worth mentioning that the new range we are giving assumes a similar performance relative to the commissioning of the company's second jointly-owned cryogenic plant in Butler County, the Bluestone Plant.

Second quarter lease operating expenses are expected to be in the range of $10 million to $12 million. We are lowering our lease operating expenses for the full year 2012 to $48 million to $53 million compared to our previous guidance of $50 million to $55 million as a result of the reductions previously discussed during the first quarter. Cash G&A for the second quarter is expected to be within the range of $5 million to $6 million and full-year is expected to fall within the previous range of $20 million to $24 million.

On Slide 8, we show our operating capital budget, which has no changes from previously announced budget of $155.3 million. We will spend approximately 85% of our capital in our operated areas and 85% of our capital devoted to oil and liquids rich projects and 15% to dry gas. More information on our 2012 capital budget is available on our May corporate presentation, which can be assessed on our company's website.

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

Patrick M. McKinney

Thanks, Tom. Looking there at Slide 9 on our operated area highlights. We placed the Cheeseman #1H, our first Butler unit to dry gas well, into service and has been producing our test rate of 5.3 million cubic feet per day over the last 30 days. When we say test rate, what we mean is the well is still producing up casing, recovering well fluid awaiting the installation of the velocity string or tubing in the well. This work over is scheduled in May and at that time, we should be able to see a more representative production and pressure profile on the well, but today, the well is meeting our expectations. We've also completed and placed into service all 7 wells on the Grosick pad. We have completed frac-ing operations on the 2 Carson wells utilizing our reduced cluster spacing or "Super Frac" design. I will talk a lot about this aspect on the next slide.

Additionally, the 5 Gilliland Marcellus wells are currently undergoing frac-ing operations. This pad also contains our Upper Devonian per cat test, the Gilliland #11-HB. This entire pad will come online with conjunction with the Bluestone cryogenic plant startup. Also note, we're planning to drill and complete our first Upper Devonian Rhinestreet shale test in the fourth quarter of this year. As we've discussed before, we feel that the Rhinestreet will have similar liquids content as the Marcellus in per cat intervals. This could give us a fourth potential zone in our Butler County acreage and significantly add to the number of perspective drilling locations.

Rex is also planning to drill a Marcellus test in the northwest quadrant of our Butler County acreage, the Bergwell [ph], to test for increased liquids content or superrich concentration. By definition, you do not need to get over 1,315 feet BTU to really start to increase your liquids yields for these wells. We have examples of wells currently trending towards this northwestern area that have an increased BTU content and deliver an additional 5% to 10% of NGLs per million cubic feet at the well head. The point we'd like to make here is that even if our superrich area for Rex is only 1,300 BTU, it can still have a dramatic increase in liquids yield. And all of this is before any ethane upload.

We recently commissioned the Voll Field Compressor Station, which brought the inlet capacity of the Sarsen Plant up to 40 million cubic feet per day. Construction on the second cryogenic facility, the 50 million cubic feet per day Bluestone Plant, is continuing as scheduled and we expect the plant to be commissioned by the end of May.

Lastly, concerning our acreage position in Butler County, as Tom mentioned, we now have an increased position to 46,000 net acres in the area which we pointed out directly adds approximately 46 new net growing locations.

On Slide 10, following up on my comments concerning the Carson well fracs from the previous slide, a number of companies have been talking recently about reduced cluster spacing or RCS test. At Rex, we have been testing this completion method for over a year and performed this completion on 3 other wells in addition to the 2 jobs we recently performed on the Carson pad. The Drushel #3H has been on production the longest at just over year. We feel that it takes this amount of time to fully analyze the production results.

Looking at the results for the Drushel #3H well completion performed in April of 2011, we performed 150-foot stage size with 30-foot perforation clusters. As you can see, the well bore example of the "Super Frac" completion on the cartoon in the lower right-hand portion of the slide, and how the perf clusters and spacing compare to the traditional design. This well had a 3,000-foot lateral when we pumped the job with 21 stages. We also changed the fracs and layering sequence by varying the concentration of 100 mesh, 40-70 and 30-50 sands to increase well bore conductivity. This was also the series of wells that we concentrated on landing the lateral in the lower or the bottom part of the Marcellus interval that has higher organics.

Looking at the initial production rates, of the 24 IRP [ph] rate and 30 day sales rate, they're really not overly impressive but still in the range of our 5.3 BCFE type-curve for a 3,500-foot lateral. But what actually happens, since the initial rates, is that the well experienced a much shallower initial production decline and had a much more robust producing pressure profile. This leads us to our observations. We feel we can significantly improve well EURs by landing lower in the higher organic Marcellus section in performing our "Super Frac" design. By increasing the same concentration providing optimal well bore conductivity, we think we can significantly increase the drainage radius of our well patterns. When you take into consideration, this 8.8 BCFE EUR well at 26% liquids content does not contain ethane recovery, be eventually you are with this, and recovery will be approximately 11 BCFE or 49% liquids.

While this is a great result for a 3,000-foot lateral, it is example of one well. One thing to keep in mind for all these results is that we vary any number of factors for these tests, including lateral spacing, lateral length, sand concentration and pumping rate. On the Carson wells as an example, we are trying out a 225-foot stage design. We'll keep working to find the most consistent and the most efficient job designs.

I know we'll get a number of questions about well cost with this completion method. While it will vary depending upon a number of factors, including lateral length, number of stages, we estimate the additional cost to perform these jobs will be in the $500,000 to $1 million range per well. We are planning the "Super Frac" completion design for upcoming wells at the Pallack pad and the Plesniak pad in the third quarter. At the end of the day, our goal is to drill fewer wells and maximize production and fuel reserves.

On Slide 11, we have an update on our non-operated area in Westmoreland, Clearfield and Centre Counties. As we stated at year end, we increased the EURs for our Westmoreland wells from 3 BCF to 4.2 BCF, a 40% increase. In the Westmoreland field, we previously announced 7 wells on the Marco and National Metals pad and now producing over 120 days and the average cumulative production is 50% above the 4.2 BCF type-curve. It should also be noted that Williams performed reduce cluster spacing or RCS treatments on the 2 National Metals wells. We think that the replacement recoveries on these wells, markedly above the 6 BCF range that we originally took them up to and potentially into the 7 BCF range. Even though this is dry gas, when you start approaching these EUR levels, we feel this asset has tremendous value to Rex going forward. And as previously mentioned, Williams has done drilling for the year in this area.

Moving to Slide 12, we have the update on our Warrior Prospect in Carroll County. As Tom mentioned, we have closed the 15,000 acres previously announced. This should result in approximately 100 net drilling locations in the heart of the play. We have spudded our first well, the Brace #1H and we're close to the TD and the vertical section of the log and cut side wall course. We should have the 4,500 foot lateral drilled and ready for the frac job by the middle of June. We are working with the Dominion East Ohio on laying the web gas sales line into the well. We'll give the market an update in where we're at with this well in the second quarter conference call in August.

As Tom also mentioned, we announced the formation of a new area, the Warrior South Prospect, which is located in Guernsey, Noble and Belmont Counties, Ohio. The initial acreage contribution of 4,800 gross and 2,800 net is being obtained on a drill to earn basis. We expect to have 22 net locations in this project during implant, drill and complete a commitment well in the fourth quarter. In total, this gives Rex an inventory of 122 net drilling locations in the Ohio Utica play.

Moving to Slide 13. We have our update on our ASP project in the Illinois Basin. Production from the mid-oil unit pilot area continues to perform well. The pilot average 60.7 gross barrels of oil per day for the first quarter of 2012 as compared to a range of 65 to 75 gross barrels that we reported in the fourth quarter. The pilot continues to support the year improve reserve booking at the 13% of pour volume. We continue to move forward with the expansion of our 58 acre for our Perkins-Smith area. ASP flooding initiators are on track to commence in the second quarter of this year. In the Delta unit, we have tech course to support the technical work and should start drilling the pattern wells in the second and third quarter of 2012. This project is still on track to commence ASP in Jackson the second quarter of 2013.

With that, I'd like to open up the lines for questions and answers.

Question-and-Answer Session

Operator

[Operator Instructions] Our next question is from Leo Mariani from RBC capital.

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

Guys, just a quick question on your 2012 production guidance. Are you guys including anything in there from the oil in Utica there in Ohio?

Thomas C. Stabley

Yes, Leo, it's Tom. There is the small amount from those first 2 wells with the expectation that they would get put in line somewhere in the middle to late third quarter.

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

Okay. And obviously you guys picked up some additional acreage there in the Utica this quarter through the farm end, are you seeing other deals like that still available in the Utica?

Thomas C. Stabley

We looked at numerous transactions during the week and every other day practically, many of which are probably a little larger than something that Rex could take a look at but there are opportunities out there similar to this that we continue to evaluate. And when the right ones come along, we'd like to think we're in the position to take advantage of them.

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

Okay. And how about in Butler, you picked up some more acreage this quarter. Was that largely fill-in acreage or kind of extension acreage?

Thomas C. Stabley

It's going to be, just like we've talked about in the past, filling in existing units and then stuff that's out around the edges on the fringe but continuous to our existing block.

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

Okay. And I guess your Drushel well, you guys talked about 8.8 BCF EUR prior to ethane, is that a number that was assigned by your third-party reserve engineers?

Patrick M. McKinney

Leo, this is Pat. That's coming off our year-end number that was in the range for what we've got and we extended the type-curve, so that foundation was approved by our third-party engineers.

Operator

Our next question is from Jack Aydin with KeyBanc.

Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division

Tom, your guidance and everything is moving up. Is this in due to well performance or you're ahead of the plan or could you elaborate a little bit on that if you don't mind?

Thomas C. Stabley

Sure, the increase on the full-year is obviously a result of the successes we've seen in the first quarter. Historically, in the first quarter, we budget down slightly for the Illinois Basin due to flooding and usually the rougher winters that we experience out there. Obviously, we talked about from a LOE perspective, we didn't experience that, so that certainly contributed. We talked a lot about the Westmoreland wells continuing to outperform the type-curve and how they continue to act and we'll continue to watch those wells and how they do. But that certainly is contributing and hopefully can continue to contribute. And then lastly, just the continued results that we're seeing in Butler County, the fact that we have production now that's in line behind pipe waiting for the next plant. So as long as that plant's running and is at full capacity, we're giving them all the gas they can take. So, I think the combination of those 3 things really contributed to the beat. And then as you look forward to that start-up of that Bluestone Plant, again the mild winter has really put those guys on track to hit the timeline with hopefully very few delays. So that really is what's contributing to the overall increase.

Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division

Pat, how many of the wells, 2012 wells are you going to use to the "Super Frac" design?

Patrick M. McKinney

Well, right now Jack, we've talked about, obviously the 2 Carsons that we just did and then we've got 2 Plesniaks and 2 Pallacks on the queue. So right now, those are the ones we're looking at and we still may have a couple more as we go forward but we've got a couple. One well pads that we're drilling here in the second half that we may utilize that method on as well too, but we haven't finalized the number of wells yet.

Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division

What would it take for you to revisit your EUR per well? Is going to take by the year end, in essence, is there a chance that you might come in by year-end and revise both Westmoreland and Butler's EURs?

Patrick M. McKinney

Well, I don't know if we -- we do a midyear update as part of the borrowing base redetermination. The second one that will happen this year, we typically don't release that information. But I would feel very confident by the end of this year, that all those results will show up in our year end proved reserves.

Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division

Okay. One more questions and then I'll let somebody ask. How much acreage did you condemn in the dry gas area during the quarter?

Thomas C. Stabley

I think that the total amount was about, well, it's about 1,500 acres. It's not really condemned. It's more some fringy acreage that actually doesn't fit into any of the existing units. So we talk about it not reducing our overall well counts in those areas. Again, it's the fringe stuff, so about 1,500 acres and I think we’re still working on trying to get some trades-in on that if we can, but based on the timing and the next 6 to 12 months, most of it expiring, we thought it best to go ahead and get it written off.

Operator

Our next question is from Ron Mills from Johnson Rice.

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

On production, the guidance, especially the part that's related to well performance, any kind of suggestions or breakdown on how you think your gas/liquids split progresses through the year? I would assume some of the Westmoreland performance is driving a little bit of higher gas production than you may have thought or on average -- I guess I'm just trying to get a sense as to gas versus liquids in your new guidance?

Thomas C. Stabley

I think Ron, on the mix as you move through the rest of this year, it's really going to depend on the results that we see out of the Ohio Utica and if we can see the similar results to what the Chesapeake wells are performing at. I think that will start the trend upwards from the current 26% to 27% range. I think where Rex will really see that transition is when we move into '13 and have a more robust program in the Ohio Utica, start to see some of the impacts of the ASP program, and then ultimately in early '14, when we get the full ethane uplift and the Delta unit, the high-impact Delta unit kicks in. So I think that's kind of the transition. But I think for the rest of this year, if I was looking at it, I think you're somewhere in that 26% to 30% range.

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

Okay. And as it relates to the liquids side, just in terms of NGL pricing, it's come down most -- in most regions. You came in around 48% of WTI given where ethane and propane prices and the other NGLs are, is kind of that 45% to 50%, probably good range for NGL prices going forward?

Thomas C. Stabley

I think that's something that would be reasonable. I also think it's important to note that roughly about 45% to 50% of our NGLs is propane. So with the milder winter that we experienced and obviously the relationship of natural gas downward, that put pressure on the propane side. So I think with anything as you move into next year and you get into the fall, you may see an uptick back again based on the weather.

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

Okay, great. And can you, Pat, just describe a little bit, maybe in a little more detail what you think -- Range has done a good job at talking about lower Marcellus lateral placement and at least the reduced cluster spacing, but in terms of the layering of the different mesh province, what that is providing to you in terms of an additional benefit?

Patrick M. McKinney

Sure, Ron. And I can't give way all of our secrets, but I can just tell you that if you go look in model, all the 3 different sands we use have different sand sizes and obviously, the combination of those gives you a greater well bore conductivity in draining the gas into the well bore and extending the flow through the frac. So we go through and we model it and we try to get the highest concentration of sand at the well bore and try to have the most conductive path into the well bore. And it varies the amounts and the concentrations of those sands.

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

Okay. And then one last one, so bullet point, when you talked about Drushel well. You talked about a 10% to 20% higher well cost but potentially upwards of 50% to 60% type increase in EURs at least based on the Drushel well. But can you also talk about potential impact on drainage assumptions where using the "Super Frac" method, you may be draining a larger area therefore lowering capital cost, really seemingly increasing the development efficiencies in finding cost. Am I reading too much into that bullet point or is that in -- am I more on track?

Patrick M. McKinney

Oh, I think you're on track, I think the goal for all the operators out here in the shales plays is to get the biggest bang for your buck. And if you can more efficiently drill and complete these wells, drain more of your patterns out there and as an example, only drill 2 wells on a 3 well pad, you're going to start to get huge efficiencies. And the one thing that I'll point out is we still are early, we have a lot more room to grow as far as testing the optimal configurations and frac designs and we think we're well on our way, but we would hope that we would continue to see this improvement to get the most economic bang for our buck when we're out there drilling these wells.

Operator

[Operator Instructions] Our next question is from Neal Dingmann with SunTrust.

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

Pat, just quick question on that. First, this Brace #1H, this Utica well. Obviously, the talk out there, I think you mentioned this earlier, as far as how long the shut in these wells and then I know there is other ways of completing for this little Canadian company, and there's different ways about going about that. How do you envision this? Or I guess, you mentioned about results like on the August call, but is there a chance you might end up shutting this in longer to help the flow back later? Or could you talk a little bit about that?

Patrick M. McKinney

Yes, that's a good question there. There's more and more evidence out there in the industry that the companies are having better initial rates and the wells are performing better after a period of shut-in due to the low-water saturations and especially in the heart of Carroll County there. So we're looking at when we think we're get the gas sales line in there and we'll look at that timing compared to when we actually get the job done. But it's our plan currently to shut in the well at least 45 days before we try to bring it back, and based on the results of the sidewalk course that we cut in how that we're going to do micro seismic on how the well treats, we may make a determination to shut it in a little bit longer as well, too.

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

Okay. And then just remind me now lastly just on sort of capacity, as you built that out, besides the last pipe that just came -- pipeline that just came on, remind me now, on a going forward, on the Marcellus and Butler specifically, how you kind of looking, Pat, for growth as far as capacity growth in production growth?

Patrick M. McKinney

Well, obviously the Bluestone Plant is $50 million a day and as we talked before, it's going to take 2 to 3 months to get that up to an operating level where they can be ready to take it up and we're trying to coincide our frac jobs and our completions to go and keep in lock step with that. But as far as the takeaway, we've got the firm capacity now at $25 million and then at the end of the year that goes up to the $85 million in total. So we'll just have to go and see how the plant performs, and with the well results go and start to inch up as we get into the second half of the year.

Operator

Our next question is from Mike Scialla with Stifel, Nicolaus.

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

The 3 well drilling obligation you have in the Warrior South Prospect, Tom, I think you said that first well, you plan to drill horizontally. How about the other 2 and what are your cost going to be in those wells?

Thomas C. Stabley

We'll, I'll answer the first part. The first well has to be drilled, completed by November and the other 2 wells have to be commenced. So it's our hope to get in there and see how the first well acts, see what we get out of it, what we learn, and then go ahead and kick those other 2 off horizontal, probably in early 2012 -- 2013.

Patrick M. McKinney

And Mike, as far as the cost, we're still sticking -- that's about the similar TVD as we've got in Carroll, so we're still between 6.5 and 7.5 to drilling complete this Utica wells. And obviously, the first wells have some signs with them so we would expect that it'd be a little on the higher end from what we would hopefully as in a full development mode.

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

And is Rex going to be paying the 100% of those first 3 wells? Is that the part of the deal that you got?

Thomas C. Stabley

We haven't disclosed the full terms of the farm out. Once we get a little further along we'll give you all the details.

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

Okay. And tell me again, you added these to the plan but the budget didn't move and you swapped those up for some Carroll County wells, is that correct?

Thomas C. Stabley

Yes. We had 3 Ohio Utica wells planned. One of the 3 will now be in the Guernsey area.

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

Okay. And then can you talk about what you're seeing in this area in the Warrior South, how that might to Carroll County or what you see in terms of what you like and what the risks may be there?

Patrick M. McKinney

Well, Mike, there's a lot of thickness information out there and you're starting to get some more well results from Anadarko down there and we obviously feel very confident in the liquids window down there. We feel pretty confident on the thicknesses and until you drill the well, you're not going to be sure of the porosities and the other factors. But we like it down there and we think at least the first pass and the thicknesses and the geology looks pretty similar.

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

And switching over to Butler County, to follow up on Ron's question, I believe it was, you'd mentioned that you think you're probably improving the conductivity here with the "Super Frac", where do you think the spacing is going there?

Patrick M. McKinney

That's is great question. And I think the jury's still out on that. We plan to -- once you get the over years with production history, you got a pretty good idea of how that well's going to trend. We don't think you can make that determination with production cycle shorter than that due to just normal variations and pressures et cetera. But, we're going to do some simulation modeling and we're going to keep working to look at all the results that we've got out there including the wells that we don't do the "Super Frac" on, to try to go in model drainage to get down to what the optimum is and we're still varying distances between the lateral lengths and looking how those wells perform. So we got a little bit more work to do but obviously, if you can drain more area, you need less wells and I think the data initially is pointing to a little bit more distance between these wells than in filling.

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

I mean if you had to guess today, do you think it's going to be more than 80 acre spacing or just too early to say?

Thomas C. Stabley

No, I don't think it's going to be more than that but I don't think you're going to get down to 30 -- or 20 or 30 acre spacing. And again, I don't I depends on the laterals and what your interference is and how the units are laid out. But we feel that between 500 foot and probably 800-foot spacing between lateral will be kind of the sweet spot and again, because of our customer unit sizes out there, we don't really talk about through 40-acre or 80 acre spacing because you may have 4 or 5 wells on a unit that's a 600-acre unit. So it just depends on the pad layout.

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

Great. The Drushel you said that you actually, your auditors had blessed the 8.8 BCFE. You mentioned the 30 day rate wasn't all that impressive, can you give a longer day rate to give a sense of what that decline look like?

Patrick M. McKinney

We haven't disclosed that, but if -- we mentioned that the first year decline was about half of the normal, so you can go on our presentation and kind of look at where that might be.

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

Okay. And you mentioned the Northeast portion of your acreage or Northwest I guess is where you think you've got a higher liquids yield. How much of that acreage do you think is in that super rich area?

Patrick M. McKinney

Well, again, when we -- and maybe we shouldn't call it superrich, but if you start getting above the base BTU content that we've seen kind of in our core area, it starts to increase as you go up to the Northwest. I mean, even if you get up to 1,300 BTU or even 1,290, you're starting to get liquids yields before ethane that are going to be 10% to 30% higher than what you're currently getting and we've seen that in existing wells. So when you get the ethane up, that's going to double that. So I don't think were ready to kind of draw a line in the sand yet and say what, where that line goes. We'll keep you guys updated on as we continue to move when we get to the Plesniak and Pallacks. Those are going -- will be our first Marcellus to the Northeast and then we're going to go do the Grubbs well, which is going to be as Northwest as we can get. And we'll lay it out and let you guys see it. But we think -- we're very excited in just get another 50 BTU and get it up to 1,300, you're going to really increase your yields.

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

And I guess it's going to put more pressure on your processing limitations. Can you give an update on the status of the third processing plant?

Thomas C. Stabley

Yes. Where we are on the third plant is the permit has been submitted to the state DEP, and that the a location has been selected. So we have the location and the permit. I think a lot more clarity will be provided when we give an update in the next 2 weeks with the midstream and the Niobrara asset divestitures.

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

Okay. I guess without preempting that, is it fair to say that, that third processing plant might take advantage of the area where you think you're getting a higher yield?

Thomas C. Stabley

I think that there will be a lot more clarity with the update that will be given to the market into the next 2 weeks.

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

Okay. I tried. Along the same lines, would it be, and I don't know if you want to answer this, but I assume if you do divest the midstream to whoever buys that, is going to be responsible for building out all the remaining midstream assets for Butler?

Thomas C. Stabley

We have said that the sale of those assets are in full. So it's not just Rex's proportionate fees, it's both plants and all of the partners.

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

And going forward as well, I would assume they would take over everything?

Thomas C. Stabley

That's correct.

Operator

Our next question is from Jeff Hayden [ph] from KLR Group.

Unknown Analyst

Pat, just one more, I guess kind of looking at kind of "Super Frac" and the potential impact and then maybe it's too early to answer this but, it's going to impact spacing, but when you kind of think about the total resource potential, total recovery factor you can get from the Butler County stuff using the "Super Frac", how do you think this would impact the overall recovery factor when kind of factoring in the wider spacing, et cetera?

Patrick M. McKinney

Well, it's going to allow you to recover more of original gas in place. And I think even on the range call, they talk about taking this kind of 50% recovery factor and taking it up. So I think you're going to be able to recover more of the resource and then the challenge is to put the right number of wells to get that recovery. So I think it's going to take your recovery factors up and you just have to do it efficiently.

Unknown Analyst

Okay. And I mean, again, probably way too early, but could you quantify kind of best guess estimate impact in terms of a how much we can think of that recovery factor?

Thomas C. Stabley

No. I think if it is a little bit early to do that and I think -- again, the more production history we get with these wells, the easier it is for us to talk about that. So I would hope that as we proceed through this year and see our well results that a lot of that hopefully will manifest itself in year-end reserves.

Unknown Analyst

Okay. And then just a couple of quick follow ups towards some other comments. Clearfield, 1,500 acres, was that net or gross, that could expire?

Thomas C. Stabley

Net to Rex, it was about 1,500 to 2,000 acres, I believe. Correct.

Unknown Analyst

Okay. And the 22 potential locations, I think I heard that right in Warrior South, is that net or gross?

Thomas C. Stabley

Net.

Operator

And I will like to turn it back to Mr. Stabley for any closing remarks.

Thomas C. Stabley

Yes. Thank you again for participating in Rex Energy's First Quarter 2012 Conference Call. Have a good day.

Operator

Thank you. Ladies and gentlemen, this does conclude your call for today. You may now all disconnect. Thank you very much, and have a wonderful day.

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