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Rex Energy (NASDAQ:REXX)

Q3 2012 Earnings Call

November 07, 2012 10:00 am ET

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

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

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

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

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

Gordon Douthat - Wells Fargo Securities, LLC, Research Division

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

Jeffrey Hayden

Operator

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

Mark Aydin

Good morning, and thank you for joining us for the Rex Energy Third 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 third quarter operational and financial release.

Today's discussion will include forward-looking information and reference non-GAAP financial measures. Please review our cautionary statements in the release and the accompanying slide presentation. In addition, 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 third quarter. Production came in at 71.1 million cubic feet equivalent per day, which represents growth of 63% over the comparable quarter last year, including 17% growth in liquids. The company's total liquids production averaged over 3,000 BOEs per day for the third quarter. Our growth in liquids production is the result of continued drilling success in the liquids-rich portions of the Butler operated Area, the commencement of our liquids-focused Ohio Utica program and early successes in the Illinois Basin conventional drilling and refrac programs. In our Butler Operated Area, we have completed the 2-well Pallack pad and 2-well Plesniak pad, both utilizing our "Super Frac" design. Both of these pads were intended to test portions of our acreage that we believe may be super rich, meaning that the wells in these areas are likely to produce white gas with BTU values of 1,300 BTU or higher. With the completion of these 2 pads, we feel we have a good indication of where the super-rich 1,300 BTU line falls across our acreage. Both the Pallacks and Plesniak pads are in sales and producing at approximately 1,300 BTU and with full ethane recovery would be over 50% liquids. We're going to continue to test the liquids-rich portions of our acreage in the Butler-operated areas.

In the first quarter of 2013, we plan to complete the Grubbs #1H, a Marcellus well located updip of where we believe our 1,300 BTU super-rich line lies. We expect this project to help us continue to validate the location of the super-rich line and the increased liquids potential of the Marcellus to the north and west of this line. Additionally, we plan to drill the Burgh #1H to the Upper Devonian Burkett shale on a pad adjacent to the Grubbs #1H Marcellus well pad to test the liquids potential of shallower shales above the Super Rich Marcellus in Butler County.

In summary, the company currently believes that approximately 1/3 of its acreage in the Butler Operated Area may be perspective for the Super Rich Marcellus at 1,300 BTU levels or above. We plan to continue to test the Upper Devonian and expect those tests to confirm similar or higher BTU levels for the same area.

Staying in the Butler Operated Area, we also announced that we entered into an agreement with Enterprise Products Partners to become an anchor/shipper of ethane on the ATEX pipeline. The agreement calls for volumes to be transported beginning at 3,000 barrels per day of ethane in 2014 and increase over time to 11,000 barrels per day in 2017. This agreement gives us tremendous optionality as it opens up various markets for us to sell our ethane. In addition to Butler, a portion of our volumes committed will also be sourced from our Warrior prospects in Ohio.

Moving to Ohio Utica, during the quarter, we placed into sales our first Ohio Utica well in the Warrior North Prospect, the Brace #1H. The well-produced at an average 24-hour sales rate a 1,094 BOEs per day and 30-day sales average rate of 730 BOEs per day. The composition of the well was approximately 70% liquids assuming full ethane recovery. While this was our first completion in the Warrior North Prospect, we are encouraged by the results.

In the Warrior South Prospect, we have completed drilling all 3 of our planned wells and expect to begin fracture stimulating this pad during the months of November. Based on the data we obtained from the completion of the Brace well, the company has decided to utilize its super frac completion methodology on all 3 of the Warrior South wells. Our discussions with potential midstream providers are progressing and we expect to update the market before year end for the Warrior South area. With the completion of the third well in the Warrior South Prospect, the rig will be moving back up to the Warrior North area where it will begin drilling the second well -- the first of a 2-well pad at the G. Graham location.

Finally, before leaving the Ohio Utica, we have reached our goal of securing 20,000 acres in the Warrior prospects. The increased acreage, in addition to the infrastructure and agreements we are pursuing and those that are already in place, have us well-positioned to grow our liquids in this area of the company's development.

Turning to the Illinois Basin, we continued to move forward with our previous announced program of conventional drilling and recompletions, and results so far have been encouraging. We plan to test the company's acreage throughout the basin to identify additional opportunities for these projects. We believe the current program will provide incremental oil production of over 400 gross barrels per day in the Illinois Basin by year end. The company expects to provide a more detailed update during its fourth quarter conference call. And with that, I'd 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 14% over the second quarter of 2012 and 63% over the third quarter of 2011. Oil and NGL production for the quarter increased by 14% over the second quarter of 2012 or by approximately 350 barrels per day and accounted for 26% of our total production. We believe this trend of increasing liquid production will continue for the foreseeable future as we continue to allocate capital to develop our liquids-rich assets. Lease operating expenses for the quarter were $11.2 million or approximately $1.72 per Mcfe and towards the low end of our previously announced guidance range. The $1.72 per Mcfe is a 23% decrease on a per unit basis as compared to the third quarter of 2011 and an 11% decrease on a per unit basis as compared to the second quarter of 2012. Strong production from our additional Marcellus wells and lower operating costs for our existing wells contributed to the improvement on a per unit basis over the third quarter of 2011 and over the second quarter of 2012.

As we continue to develop our Appalachian Basin assets, we expect lease operating expenses to continue to trend downward on a per unit basis. Adjusted net income, a non-GAAP measure for the third quarter, was approximately $4 million or $0.08 per share. Net loss from continuing operations for the current quarter was $1.7 million or $0.04 per fully diluted share and includes a $10.2 million mark-to-market loss on the company's open derivative positions, largely as a result of increasing natural gas prices during the quarter. EBITDAX from continuing operations, a non-GAAP measure, was approximately $22.8 million for the third quarter or $0.44 per share, which is a 2% increase over the third quarter of 2011 and a 27% increase over the second quarter of 2012. The increase over the prior quarter was due to increased production during the quarter and higher realized prices on our natural gas and NGLs. For a detailed reconciliation of these non-GAAP measures to GAAP net income, please see the appendix at the end of our presentation.

Moving to Slide 6. We present a summary of our price realizations for the third quarter. Prior to the effects of hedging, realized prices for the quarter were $89 per barrel of oil and condensate, $2.98 per Mcf of natural gas and $40.95 per barrel of NGLs. Cash settlements from hedges increased our realized gas price by $0.85 per Mcf for the quarter, resulting in a net price of $3.83 per Mcf. Realized prices for NGLs were also positively impacted by hedging activities during the quarter, increasing our realized price by $1.60 to $42.55 per barrel.

Onto Slide 7, we present a summary of our current hedge position. For the remainder of 2012, we are over 70% hedged with cost of colors [ph] on our oil production and over 60% hedged on our gas production at prices in excess of the current strip price.

Looking ahead to 2013, we have a significant hedge position in place for both our gas and oil production, which will provide predictable cash flows as we execute our capital program. We have over 65% of our 2013 oil production hedged using cost with colors [ph] and approximately 70% of our 2013 gas production hedged at what we believe are attractive levels. We are continuing to layer on hedges for both gas and oil in 2014 as opportunities present themselves.

Moving to Slide 8, we would like to discuss our fourth quarter 2012 and our full year guidance. We expect fourth quarter daily production to average between 70 million and 74 million cubic feet per day. This is an increase of 1% over third quarter's production at the midpoint of the guidance. Fourth quarter lease operating expenses are expected to be in the range of $11.5 million to $13 million. Cash G&A expenses for the fourth quarter are expected to be in the range of $5.3 million to $6.3 million. For the full year 2012, we are maintaining our guidance range of $46 million to $50 million for LOE. We are also maintaining our 2012 cash G&A guidance range of $20 million to $24 million. With that, I would like to turn the call over to our President and Chief Operating Officer, Patrick McKinney.

Patrick M. McKinney

Thanks, Michael,. Turning to Slide 9 on our Butler Operated Area highlights and echoing Tom's opening remarks, we are excited to continue to see an increase in our reserves and liquids potential as we delayed our super rich area in the Marcellus in the field. The 2 wells on the Pallack pad were completed using our "Super Frac" design and placed into sales during the third quarter. The wells produce an average 5-day rate of 4.4 million cubic feet equivalent per day and average 30-day rate of 3.8 million cubic feet equivalent per day per well. This assumes full ethane recovery. Our initial analysis of the payout indicate 1,300 BTU gas with a 56% higher C3 plus liquids concentration as compared to the average Butler Operated Marcellus wells. As a point of reference, this takes the net C3 plus recovery from approximately 37 barrels per million cubic feet of inlet gas to 58 barrels per million of inlet. When you factor in ethane recovery, this yield would increase from approximately 118 barrels per million cubic feet of inlet to 147 barrels per million. Both well rates were under conditions of restricted choke production flow test. We also completed the 2 wells on the Plesniak pad using the "Super Frac" design and placed into sales the Plesniak 3H while the Plesniak 9H is being shut in for 60 days. The 3H produced at an average 5-day rate a 4.5 million cubic feet equivalent per day and a 25-day average rate of 4.3 million cubic feet equivalent per day, again, assuming full ethane recovery. Our gas analysis of the 3H also indicated 1,300 BTU gas with similar liquids increases and yields as we discussed earlier on the Pallack wells. The initial flow rate on the Plesniak 3H was also under conditions of restricted choke production flow test. We are testing the restricted choke on the wells to limit drawdown pressure on the shale face in an attempt to minimize any formation damage during the completion process and reduce the amount of flowback water. The extended shut-in period is based on lower water saturation seen on Marcellus cores in Butler combined with a higher liquids concentrations, similar to the industry practice in the Ohio Utica. Of particular significance of these 2 Marcellus results was that we not only saw a dramatic increase in C3 plus liquids and ethane but also in associated condensate production. We are now looking at Marcellus EURs to continue over 54% of total liquids or to put this into context, these super rich wells contain over 500,000 barrels of liquids per well when you include the ethane.

We are currently drilling our third Upper Devonian Burkett well to continue to prove up the increased liquids content of this play in the field. With one more Upper Devonian well to drill in 2012, we'll have an inventory of 3 Burkett wells scheduled for completion in 2013. We also have 2 more Marcellus data points that we believe are above 1,300 BTU super-rich line with both the Wack and Grubbs wells currently scheduled to be completed in 2013.

Lastly, we are completing the test of the Upper Devonian Rhinestreet in a vertical legacy wellbore. We expect this integral to contain even higher liquids content as compared to the Marcellus and Upper Devonian Burkett zones. The well is currently flowing back and we expect to have results of its liquids content in the fourth quarter of 2012.

For the full year, we plan to have drilled 20 gross wells in Butler, frac 20 and place a total of 21 into service. Our yearend inventory wells drilled and awaiting completion is currently projected to be 18.

Slide 10 is a summary of our "Super Frac" Marcellus completion characteristics. You can see that we have extended production history on the Drushel and Behm wells that serves to validate the shape of our "Super Frac" type curve, which exhibits a much slower initial decline rate. The Carson wells have now been producing close to 150 days. The Pallack wells have been into sales for 60 days and lastly, the Plesniak 3H has been online for close to 30 days.

As we've stated previously, we've intentionally varied certain completion characteristics of these wells to test different practices in an effort to maximize our completion techniques and achieve the highest recoveries at the lowest capital cost.

As we see more production history, we'll continue to evaluate all aspects of these completions, including spacing between wells, restricted choke flowback and extended shut-in periods. Ultimately, we would expect our analysis to help us determine an optimal completion practice for the development of Marcellus wells going forward with a goal of increasing our EUR type curve for these wells.

Moving to Slide 11, we have an update on our Warrior North prospect in Carroll County, Ohio. In September, we placed into sales our first Ohio Utica well, the Brace #1H. The well produced at an average 24-hour sales rate, 1,100 BOE per day and a 5-day rate of 1,000 BOE per day and now a 30-day sales rate of 731 BOE per day. Adding some color on the completion of the Brace #1, we wanted to test the viability up our "Super Frac" completion method in the Ohio Utica so we utilized microseismic to evaluate the effectiveness of the frac. We frac-ed the first 10 stages in the toe of the well, a conventional 300-foot stage spaces -- space stages on 60-foot intervals. On the final 7 stages in heel of the well, we utilized our "Super Frac" design on 150-foot stages, 30-foot spacing. From the microseismic results we saw a much better frac energy, fracture concentration and fracture coverage from the "Super Frac" in both the Point Pleasant and the Utica sections. As a result, we're planning to use the "Super Frac" completion design on our Utica wells in this area. As Tom mentioned earlier, we are moving the rig to the Warrior North prospect to the G. Graham pad. We've estimated that we have over 70 net drilling locations in our Warrior North project.

Moving to Slide 12, in our Warrior South area, where we added 800 net acres during the third quarter, we recently our TD-ed our third well, the Guernsey [ph] 2x. This is the final well of a 3-well commitment in this area for 2012. We expect to begin completion operations on the pad this month. Lastly, as Tom previously mentioned, we have achieved our goal of securing 20,000 total net acres in the combined Warrior prospects.

On Slide 13, we want to provide some detail on the midstream and infrastructure in our core are -- our core focus areas. As you can see on the map with over 1 Bcf per day of processing capacity under construction, we are very well-positioned to move our product into multiple markets. With the announcement of our agreement with Enterprise Product Partners to become an anchor/shipper of ethane on the ATEX pipeline, Rex has secured access to the Gulf Coast ethane markets.

With our ethane out of Butler going to the MarkWest, Houston Pennsylvania complex. We also have access to both the Mariner East and Mariner West projects. In Ohio, we are also well positioned with our relationship with Dominion East Ohio and Warrior North in a number of different outlets to serve our Warrior South acreage. We think our existing agreements and prospects in these areas will provide us with top-tier midstream partners and further enhance our development in Appalachia.

Moving to Slide 14, as Tom mentioned in his remarks and with keeping with our focus on increasing our liquids production, our technical teams have identified a number of recompletions and infill drilling opportunities in Gibson and Posey counties in Indiana. We previously issued guidance for incremental oil production of 250 to 400 gross barrels per day of oil by the fourth quarter of '12. Through the third quarter, we have drilled 7 infill wells and recompleted 7 existing producers. For the full year 2012, we anticipate recompleting an additional 7 wells. To-date, we have seen results that if sustained would exceed our previous guidance. Based on this success, we continue to evaluate additional liquids opportunities throughout our other acreage in the basin.

Slide 15 gives us an update in our ASP projects in the Illinois Basin. In the high impact Delta Unit, we have completed drilling -- completed the drilling of pattern injection producing wells. We're continuing our core flood work and reservoir simulation modeling in the Delta Unit, and we expect to be able to book proved reserves on the project as early as yearend 2012. Full ASP injection of the Delta Unit is still on schedule to begin the second quarter of 2013 with initial response in 2014. Peak response had an estimated 13% of core volume recoveries expected to occur by mid-2015 at a rate of approximately 1,000 gross barrels of oil per day. In the Perkins-Smith Unit, we commenced ASP injection in the second quarter 2012 and expect to see initial project response by the second quarter of 2013.

For the third quarter of 2012, the mid-op ASP pilot continues to support the 2011 year end proved reserve bookings of 13% before volume recovery.

Slide 16 is an update of our non-operated area in Westmoreland, Clearfield and Centre Counties. In the Westmoreland field the previously announced 7 wells in the Marco #1 pad and the National Metals #1 pad are now producing over 200 days and their average kilo to production is still trending 50% above the type curve. In addition, the EURS on the last 12 wells completed by the operator, WPX Energy are all exceeding the 6 Bcf type curve. As we previously announced, WPX Energy has informed us it is done drilling and frac-ing in this area for the remainder of the year.

With that, I'd like to open up the lines for the question-and-answer session.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from the line of Ron Mills from Johnson Rice.

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

A question on the arrangement with Enterprise and, Pat, you just mentioned the ability to also have the year arrangement at the Houston plant to get to Mariner East and West. Can you talk about the build in those commitments on ATEX the 3,000 to 11,000 is that split evenly as we move year-to-year? And is that about all you need, you think, from a capacity standpoint? Are you also trying to secure additional outlets for maximum flexibility?

Thomas C. Stabley

Ron, it's Tom. The 3,000 and 11,000 was expected to be a ramp over that time period. So from '14 up to '17. It is not all of our capacity. As we've previously mentioned, we would like to secure an additional outlet, whether it's Mariner East or Mariner West for additional volumes for Rex to get its ethane out of the Houston facility. So we felt like that was our first market, and again, we're looking at the other 2 and should have an update on those as we move towards the end of the year.

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

Okay, great. And in terms of the Utica results, the Brace -- 30-day rate for the Brace is impressive and you talk about the 3 completions in Warrior South. If those start here in November, is the plan to get all 3 of those wells completed here or here in by year end or what's the time frame as we look to the Utica to continue to increase in level of contribution?

Thomas C. Stabley

Well, Ron, right now the first well is in the budget as we have it laid out. We expect to be down there, here, middle to late November. Once the frac crew gets in there, depending on how the timing and how that first one goes, we plan to continue the process. So there is a chance we could get all 3 completed by the end of the year. Obviously if we do that, it would be an addition to our current capital budget but would put us ahead for 2013. The hook up line after a 60-day shut-in we still think is going to be there in time for late first -- depending, on which way we go so we're anticipating to be able to have those wells into sales by the end of the third quarter or the end of the first quarter of '13.

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

And then when you -- as you go through your budgeting process for next year, you look at Warrior South and Warrior North, is -- are you thinking about potentially running a rig in each area or would you continue to shuttle a rig between your 2 project areas or how would you look to draw that up?

Thomas C. Stabley

What we've put out in the last update was we expect to run a 1-rig program in the Utica for next year in the current preliminary plans. So we'd probably do an additional 4 wells down in Warrior South and then the remaining 8 to 9 wells in Warrior North, that's kind of the preliminary plans right now. Obviously, as we get more data we'll update that.

Operator

And our next question comes from the line of Brian Velie from Capital One.

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

I just have one quick question on the Plesniak well. I guess it's been online for about 60 days now and you did release a 30-day average. I wonder if the 60-day average was available and if it was still tracking, I guess, consistent with the other "Super Frac" results?

Thomas C. Stabley

Well, the Pallacks are the ones that are 60 days. The Plesniak is 30 days, Brian. That's all right. But we haven't disclosed any rates on those outside of what we've given but we feel that we're pleased with the initial rates that we've seen so far today and obviously their restricted flow. And so where gathering all this information up, and we're going to continue to analyze it. But we're happy with our performance today.

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

Okay, great. And then one other question, I think you may have addressed this at times in the past but it sounds like with what you've seen in the Utica, with the partial super frac completion and plans there to do the future wells using the same completion method, is it safe to say that that's kind of the new normal and it's applicable to, I guess, any well, Marcellus or Utica, that you'd be drilling in, in the end of '12 and into '13?

Thomas C. Stabley

Well, I think, Brian, that we really like what we've seen from the "Super Frac" design and I think the microseismic kind of confirmed a lot of things that we already knew. And I would tell you here, we'll give you more color when we rack up the budget, but we're probably leaning that way right now.

Operator

And our next question comes from the line of Neal Dingmann from SunTrust.

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

Just to say, Tom, for you or Pat, just first on the Utica, 2 things, first on lateral lengths, your thoughts, was it more -- some of the peers have gone a little bit longer. Just your thoughts for either one that you're all on, kind of where you're at now and is that will kind of be the norm going forward around, if that has anything to do with your design? And then secondly, around the Utica, I think you said 800 more acres. Certainly, the financial flexibility if you want to go out and get more, is there more acreage out there? Would you want to go after more acreage, either in the North or South?

Patrick M. McKinney

Neal, this is Pat. I'll comment on the lateral lengths initially. We're kind of limited by the size and shape of the acreage blocks that we're in, so our lateral lengths are kind of driven by that. I would probably comment and tell you that if our Super Fracs work the way we think we -- that they are -- we feel we're going to get the best out of whatever lateral length we put out there. So we have the opportunity to go a little bit longer as we look into next year but again, those are going to be driven by kind of the acreage position that we've got.

Thomas C. Stabley

Yes. Neal, it's Tom. On the land side, we certainly continue to look at additional acreage in the Warrior South area. There is some additional acreage available. We do feel again that it's very important to have a continuous block, so we're looking to pick up scattered tracks. We're looking to bolt-on and add additional locations, and we do think there's some opportunity for that. So we'll continue to update you on that and probably have some additional updates as we get into the budgeting process for year end.

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

Okay. And then looking at just sort of the CapEx going forward, I noticed that about $14 million was spent more on conventional stuff, including ASP. I was wondering, Pat, maybe to keep the ASP up or the rate continued up, I mean what will kind of be the expense for that going forward and what kind of ramp I guess? You've talked a little bit about what kind of liquids that can throw off maybe give an idea of what you'll have to spend and kind of what we can expect on production there next year.

Patrick M. McKinney

Well, sure. We've kind of put a marker for the Delta project that are around $30 million out there that we put in our releases today. So we've spent a good chunk of that drilling this year and then we've always got the ASP injection which starts next year. And as we've said, we're going to see a little ramp in '14 but we're not going to see the peak production of the Delta till mid-'15 so we're in that time frame. So going forward we were pretty consistent in saying that the ASP budget really shouldn't be more than 10% or 15% of our total CapEx. So I think we still feel pretty good about that range.

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

Okay. And then just lastly, on the Butler area we're just looking at that map again on Page -- on the Slide 9. But kind of where you do you draw that line. I guess 2 questions around that. First just, Pat, your thought or for you, Tom, as far as Devonian, I know you mentioned about further testing for some increased liquids, will -- I guess maybe a silly question but will the liquids potential on the Devonian in the same region that your sort of think is perspective for the Marcellus as well, is that going to be kind of grouped in the area. And then your well costs certainly have come down. Will those continue to come down next year on just sort of design techniques, et cetera?

Patrick M. McKinney

Well, just to comment on the liquids content. As we go up this track column from the Marcellus to the Burkett to the Rhinestreet, just going up also increases the liquids content, really in any where you're at. When we draw the 1,300 BTU line, we feel really all 3 zones are in play definitely as you get above that very increased liquids content. We previously reported that our Upper Devonian Burkett well was about 16% increased liquids in the adjoining Marcellus well. So you're going to have some liquids concentration increase even below that line, but we feel really anything above that line all 3 zones potentially are in play. And then I guess, could you repeat the last part of your question on the capital?

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

Just wondering on the well cost. You, certainly over the course of this year, had your Marcellus, both the Butler and some of these other Marcellus well costs come down pretty nicely as you do pad drilling and some of other completion, your new completion techniques, how much more can you get out of those well costs?

Patrick M. McKinney

Well, I think we've been pretty consistent talking about until we get to really full pad drilling and get out of kind of an HBP mode that we're in at least for the next couple of years. I wouldn't look to see a tremendous drop. Once we can go and get the efficiencies and the scale for pad drilling, I think you'll see a big drop, but as some Tom has mentioned before with the contiguous acreage position in Butler. We're really looking to have -- to capitalize on that, have some scale and obviously not only work on capital side, but work on the LOE side. So we feel having that acreage position blocked up the way we do is really going to help us. But longer-term, the drilling costs, we're always working to go and cut them down, but you're not going to see a big step change until we get to a lot more pad drilling.

Operator

And our next question comes from the line of Leo Mariani from RBC.

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

Just looking for a little clarity around the Utica. Is that first Brace well constrained at all or choked back? You talked about restricted choke on a lot of the wells in Butler. Are you planning on doing the same thing Utica for now? And just any maybe processing constraints you're seeing, any color on that?

Patrick M. McKinney

Well, I'll answer the choke-back, Neal, and I'll let Tom answer any kind of processing issues but these wells are pretty much industry practice. Most of the operators keep them choked back on not much more about 24-inch choke as we go through at least the first 6 months or year production. So yes, it's choked-back and obviously, it's into sales so we're having to buck line pressure and separator pressure, so that's one thing that probably a little bit more unique as compared to some of the other well results that are out there. But that's our plan, just continue to go and really manage the drawdown pressure we're seeing in the reservoir.

Thomas C. Stabley

Yes, on the processing side, we're flowing into Dominion East Ohio going down to the Hastings plant. We've got firm transporting and processing into Hasting, so we have no issues there. The Natrium facility where we have our $15 million of processing is on schedule to be complete towards the end of this year, so sometime later in December. So once that's completed, we'll switch from Hastings to Natrium. So no real issues there and that $15 million should get us well into next year as far as midstream and takeaway goes. And then on the Warrior South, again as we've said, we've got several options down on takeaway and should have something wrapped up here, probably before the end of the year.

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

Okay, and I guess on the restricted choke programs that you talked about in Butler, what were the choke sizes there that you're using.

Patrick M. McKinney

We really haven't disclosed those, Leo, but they're in a range that really don't give much up above 32, 34s, 64s.

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

Okay. And I guess just looking at your costs, what are you guys seeing in terms of your well costs in the Marcellus with the "Super Frac" right now and what did that first Brace well cost you guys?

Patrick M. McKinney

Okay. That's a good question, Leo. I mean I think we're starting to see some scale, some efficiencies in our Marcellus costs, and we have previously kind of put a range out there for the "Super Frac" a 6.2 to 6 4. We're going to work real hard this year to try get below that range. Our Brace well cost in the $9 million range and obviously the first well in the program out there we've been able to see as we've continued to drill 3 more wells, really cut some days off. So our goal is to try drive that number down as we continue to drill more wells out there.

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

Okay. And you also talked about having some Upper Devonian results, when will you expect that next few wells to come out there? I think you guys are getting ready to frac those pretty soon.

Patrick M. McKinney

We've got them scheduled in 2013 now, Leo, and we'll give you some more color when we've finalized our budget here and be able to kind of give you some exact dates when those things should be on.

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

Okay. And I guess in terms of dry gas drilling, obviously, part [ph] has pulled that back. Clearly, dry gas prices have moved up, a fair bit any discussions you've had with Williams about starting that program back up given the recent increase in gas price?

Thomas C. Stabley

I think at the present time, the plans, your preliminary plans for '13 would look at the 7 to 9 wells that we have in inventory in Westmoreland so we could get in and frac those, but currently there are no plans for additional drilling.

Operator

And our next question comes from the line of Gordon Douthat from Wells Fargo.

Gordon Douthat - Wells Fargo Securities, LLC, Research Division

As it relates to your ethane agreement. Can you just give us a little color on how the SEC views having that agreement in place with respect to your reserve bookings and what that might allow you to do there?

Patrick M. McKinney

Yes, Gordon, this is Pat. Most of the recent interactions between our third-party reservoir engineering firm and the SEC indicates that once you have sales commitment that is executed to deliver the product to the markets that you can book those reserves.

Gordon Douthat - Wells Fargo Securities, LLC, Research Division

Okay, so you've got a slide in some of your recent presentations that just compares your proved reserves as of year-end 2011 before and with an ethane solution in place. Is that sort of a guideline that we should be looking at as we think about year-end reserves? Is that a fair assessment there?

Patrick M. McKinney

Well, I believe that slide shows as of yearend of 2011 what it would it be. Obviously, with another year of activity, your base is going to go up. So -- but that's probably a pretty good proxy for what it was at the end of 2011.

Gordon Douthat - Wells Fargo Securities, LLC, Research Division

Okay and then, Pat, you mentioned with the ethane agreement in place the EURs would include about 500,000 barrels of liquids, including ethane.

Patrick M. McKinney

That's correct.

Gordon Douthat - Wells Fargo Securities, LLC, Research Division

What is that split in the liquids side between ethane, propane and C3 plus, et cetera?

Patrick M. McKinney

About 2/3 ethane, 1/3 C3 plus.

Gordon Douthat - Wells Fargo Securities, LLC, Research Division

Okay. And then last question for me. Just on your 2012 CapEx, it looks as if your -- if you analyze -- or annualized the run rate for the first 3 quarters, fourth quarter, if you were to hit your guidance at $180 million, it would have to come down some, just maybe wondering if you could shed some light on what your plans are in the fourth quarter and how you feel about that $180 million target.

Thomas C. Stabley

Yes, Gordon, it's Tom. Well, I think as we mentioned earlier with Ron, we currently have just the one the Guernsey Noble scheduled in that program. The frac crew will be moving in here later in November and I think once they get situated and we can see if we could possibly get all 3 of those wells done obviously that's not in there, if we get those additional 2. And then the opportunity for once that rig gets back up to Carroll, if we can seek one more Brace well in or one more I think it's G. Graham well, we'll take a look at that. But right now, we have no additional fracs scheduled in Butler for the remainder of the year so that's a big gating item on that capital budget.

Operator

And our next question comes from the line of Mike Scialla from Stifel, Nicolaus.

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

Trying to figure out what I should model for ethane now with your enterprise agreement in terms of a deduct from a Mont Belvieu price. Can you give us any kind of sense for that?

Thomas C. Stabley

Right now the current ATEX line, our deduct on that is about $0.155 so our costs to get from Houston down to Mt. Belvieu is about $0.155. I think you could probably use about somewhere in the range of about $0.20 to $0.21, maybe $0.22 for the all-in costs to get fractionated out of Butler and all the way to Mt. Belvieu.

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

Got it. Okay. And then, Pat, not to beat it to death, I guess I didn't understand completely. I just want to clarify that, the 500 barrels on the super-rich, that was just the liquids number, right? You're not talking BOE?

Patrick M. McKinney

No, that was just straight barrels of total NGLs of C3 plus and ethane.

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

And what's a good total EUR for those wells now?

Patrick M. McKinney

Well, we're going to update the market here once we get a little bit more production history. And, obviously, our goal is to come up with what our type crew is and give you all those exact splits but we're not quite there yet. We need a little bit more production history.

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

Okay. And the extended shut-in you did on the Marcellus well, where you said you're seeing lower introduced water saturation, I guess, is that specific to the super rich area or are you seeing that in other parts of the Butler County as well?

Patrick M. McKinney

Mike, we've seen some information on some earlier wells that just were shut-in, waiting to get hooked up to sales, but their curve was a little flatter. The reservoir pressure stayed a little stronger. We do believe that the increased liquids concentration, as is kind of the thesis in Ohio when you start getting the condensate and more liquids that, that also plays a part so. From the core work that we've done, we know our water saturations are not quite as low as in the Ohio Utica and Point Pleasant but they are lower than the traditional reservoir. So we're just going to take a look at it and see if it has any benefit to us.

Operator

And our next question comes from the line of Jeff Hayden from the KLR Group.

Jeffrey Hayden

Tom, just kind of a follow-up on the CapEx question, can you give me what the land budget has been for the first 9 months of the year?

Thomas C. Stabley

Jeff, yes, the total for the first 3 quarters of this year has been about $40 million to $45 million.

Jeffrey Hayden

Okay, great. And then just kind of looking to 2013, could you just give a little color around what the Butler program is going to look like from kind of the super-rich versus, I guess, the sub-1,300 kind of BTU area, how do you kind of see that split going?

Patrick M. McKinney

Jeff, this is Pat. We've got a couple of wells that have been drilled that are awaiting completion up there north of the line so we're going to get after those. We haven't really set our total CapEx budget in drilling order yet but, as we mentioned, we still have to go in HBP out there. So we're going to try to go out and get as many data points as we can up north and still go and hold our acreage. So we'll give you all some more color on that when we set the budget and come up with a drill order and completion order.

Operator

And that concludes our question-and-answer session for today. I'd like to turn the conference back to Tom Stabley for any concluding remarks.

Thomas C. Stabley

Yes, thank you, all for participating on our third quarter conference call, and we'll look forward to seeing you at year end. Thank you.

Operator

Ladies and gentlemen, thank you for your participation in today's conference. This does conclude the program and you may now disconnect. Everyone, have a good day.

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