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Rex Energy (NASDAQ:REXX)

Q4 2011 Earnings Call

February 22, 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

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

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

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

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

Operator

Good morning, and thank you for joining the Rex Energy Corporation conference call to discuss full year and fourth quarter 2011 operational and financial results. [Operator Instructions] I would now like to introduce Tom Stabley, Chief Executive Officer of Rex Energy. Please begin.

Thomas C. Stabley

Good morning, and welcome to the Rex Energy year end conference call. During the call this morning, we will be making forward-looking statements and statements referring to management estimates. Please see the cautionary notes regarding these types of statements in the March corporate presentation posted on our website. We will also refer to certain non-GAAP financial measures like EBITDAX and ask that you refer to the reconciliations in our earnings release for additional information.

Moving on to Slide 4. I would like to take you through some of the key achievements for Rex Energy from the past year. 2011 was a story of growth and execution for Rex Energy. During the year, we drilled 31 gross, 19.8 net wells in our Butler County, Pennsylvania Operated Area and participated in the drilling of 27 gross, 10.4 net wells in our non-operated areas in Westmoreland and Centre counties, focusing predominantly on the Marcellus Shale. During the same period, we placed into service 21 gross, 13.9 net wells in Butler County and 30 gross, 12 net wells in our non-operated areas.

Finally, in our Butler area, we ended the year with an inventory of 19 gross wells drilled and waiting completion. These 19 gross wells provide us with an inventory to begin completions in advance of the commissioning of our second cryogenic processing facility, the Bluestone Plant. The Bluestone Plant will have inlet capacity of 50 million cubic feet per day and is scheduled to be commissioned in May of 2012.

With the success of our 2011 drilling and completion program, our average daily production rate grew by 92% over 2010, and our December exit rate increased 119% year-over-year. Our fourth quarter production growth of 12% over the third quarter represents our fifth consecutive quarter of double-digit production increases.

In addition to our 100% success rate in the Marcellus Shale, we also drilled and completed 2 successful test wells, one in the Upper Devonian/Burkett shale and the second in the Utica Shale. These wells also demonstrated that the Burkett and the Utica Shales are commercially viable in Butler County acreage, providing us with the potential of the 3 separate commercial zones throughout our 67,000 gross, 45,000 net acres in Butler County.

Leasing during 2011 was predominantly focused on acquiring and growing our acreage positions and our liquid-focused plays in the Appalachian Basin. We are very excited about our 15,000 acres in the Warrior Prospect in Carroll Country, Ohio, which we believe will be perspective for the liquids portion of the Utica Shale. We announced last evening in our press release that we are planning to spud our first well in Carroll County during April of this year.

We also continued our leasing campaign in our core operating area in Butler County throughout 2011. We opportunistically leased or traded into approximately 10,000 net acres -- 10,700 net acres, bringing our total acreage in Butler County to 67,200 gross or 44,800 net acres.

In our Illinois Basin, after much hard work and a success brought about by our ASP project team, we booked proved reserves in 2011 from our Middaugh project in the large field. With these results in hand, we are moving forward with the next phase of development in our Perkins-Smith Unit in 2012. And in 2013, we are planning to shift our focus to the high-impact Delta unit, where the production from that project in the previous 2 could potentially double the existing production in the field.

Finally, our successes in 2011 translated into an increase in our operating revenues of 67% over 2010, growth in earnings per share from continuing operations of 128% year-over-year and an increase to EBITDAX of 139%. To sum up, we successfully executed our strategy in 2011, and execution resulted in a significant growth production in revenues. The growth will help to position Rex to achieve the objectives we have laid out in our 2012 plan.

On Slide 5, I'd like to draw your attention to a few important points. Our per-unit lease operating expense and cash G&A expenses continued to decrease as we ship more of our production base to areas with lower operating costs. Although our lease operating expenses increased $2.6 million for the quarter and $8.4 million for the year, our per-unit lease operating expenses decreased 35% and 30%, respectively. Similarly, our cash G&A and administrative expenses increased $0.5 million during the quarter and $5.8 million during the year, while decreasing on a per-unit basis by 48% and 29%, respectively.

I would also like to note that with the successes we've achieved in our ASP project and the large field water enhancement projects, the company was able to slightly increase oil production in the Illinois Basin. That is a significant accomplishment in a mature field, and we're very pleased by these results.

Slide 6. Moving to Slide 6, we provided you with an update of our current hedging position. Currently, we have approximately 67% of our 2012 Q1 midpoint guidance gas production hedged in floors of approximately $4.50 and 89% of our 2013 gas production hedged at floors of approximately $4.44.

This solid natural gas hedged book provides the company a stable cash flow during these types of lower commodity prices and affords us the ability to continue executing on our plan of targeting Rex's large inventory of liquids-rich drilling opportunities. I would encourage you to review our complete hedging position, a summary is available in the appendix of this presentation.

In our release last evening, we have outlined our revised capital budget for 2012. Slide 7 shows the breakdown and allocation of the revised capital budget. We reduced the previously announced capital budget by $34.4 million or roughly 18% from $189.7 million to $155.3 million. The capital reductions have come predominantly from our non-operated dry gas area in the Marcellus Shale and also, reallocations of our Utica dry gas play, 2 additional liquids-rich wells in Butler County.

This change will take our non-operated dry gas areas from 17 gross to be drilled to 7 and a reduced number of fracs from 16 to 1. We are also replacing 2 dry gas Utica wells in Butler County with 2 Marcellus wells and an Upper Devonian/Rhinestreet completion to further test the liquids-rich portion of this zone. More information on our revised 2012 capital budget is available in our March corporate presentation, which can be assessed on our company website.

On Slide 8, we have provided our updated guidance. We have decreased capital spending in our dry gas areas previously discussed in 2012 from our $189 million to $155 million or again roughly 18%. With this reduction in capital, Rex is still targeting 68% growth year-over-year at the midpoint of its revised guidance. New revised full year production guidance has reduced from the previous range of 66 million to 72 million cubic feet equivalent per day to 63 million to 68 million cubic feet equivalent per day, or a reduction of approximately 5% in the midpoint of this new range.

Lease operating expenses and cash G&A guidance will remain unchanged for the year.

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

Patrick M. McKinney

Thanks, Tom. Slide 9 summarizes our 2011 proved reserves. Proved reserves increased 82% over 2010, with 47% of our 2011 reserves in the proved develop category. Since 2009, we have roughly tripled our proved reserves to 366.2 Bcfe. Similarly, our SEC PV-10 Value has increased more than threefold to $539.6 million.

Other stats worth mentioning from our previously released year end reserves are that we successfully replaced 1,093% of our 2011 production at a 3-year average drill and finding development cost of $0.88 per Mcfe. We continue to conservatively book pad locations with our ratio of pad to PDP wells in the Marcellus Shale at 1.27:1.

Moving to Slide 10, I'd like to give an operational update on our Butler County Operated Area. We recently commissioned a Voll field compressor station, which will bring the inlet capacity of the Sarsen Plant up to 40 million cubic feet per day.

Construction on the second project facility, the Bluestone Plant, is continuing as scheduled, and we expect to commission the plant in May of this year.

In 2011, we increased our EUR assumptions for our Butler County area wells in the Marcellus from 4.4 to 5.3 Bcfe based on a 3,500-foot lateral length and 12-stage frac. This an increase of 20% over 2010 type curve, with several of our wells currently producing above this increased type curve.

We recently finished fracture stimulation of our 4 remaining wells out of the 7 well gross Grosick pad. All 7 wells on the pad are now completed and placed into service. The wells are performing as expected, and we plan to release flow rates in the future.

We have also completed drilling operations on the 2-well Plesniak pad and are continuing to move forward with our Butler area drilling plan for 2012.

We continue to focus our drilling program on liquids-rich production in the Butler area. As mentioned earlier, we're adjusting our 2012 Utica Shale drilling program in Butler. In our previous 2012 capital budget, we're expecting to drill 3 Utica Shale wells in Butler. We continue -- with the continued low prices in natural gas markets, we're reducing our Utica Shale well count from 3 wells down to 1 well.

The 2 Utica Shale wells that will move from the drilling schedule will be converted to 2 Marcellus Shale wells. Moreover, we have included a well to test the Upper Devonian/Rhinestreet Shale in Butler. The Rhinestreet Shale well is expected to be liquids-rich and perhaps slightly higher in BTU content as compared to a Marcellus or Burkett shales. If successful, this will give Rex 4 significant producing zones in our Butler County acreage.

In fact, one of the planned Marcellus wells and a Rhinestreet well are in area of Butler County that Range Resources, this morning, depicts as superrich containing 1,350 BTU gas.

On Slide 11, we have an update on our non-operated area in Westmoreland, Clearfield and Centre counties. We've increased our EURs for our Westmoreland wells from 3 to 4.2 Bcfe, an increase of 40%. In the Westmoreland field, the previously announced wells on the Marco #1 pad and the National Metals #1 pad have been producing at an average 30 day rate of 4.4 million cubic feet per day per well, with the average 60-day rates of 4.1 million cubic feet per day.

The 30-day rates on these wells are approximately 41% higher than the current type curve, while the increase over the cumulative 60-day type curve is 56% higher. We feel that these wells represent a more accurate picture of quality of the wells in this field.

WPX has recently finished drilling the final well on the 3-well Corbett pad and is moving the rig to the Gera pad, where 1 gross well is planned. As stated earlier, we're reducing our capital budget for our non-operated area in 2012. We now are expecting to drill 7 gross wells in 2012 and fracture stimulate 1 gross well. This will leave us with 10 gross wells drilled and awaiting completion at the end of the year. I'll again direct you to our corporate presentation, which is available on our company website, for more of these details.

Moving to Slide 12, I'd like to give an update on the progress of our Warrior Prospect in Ohio. As Tom said earlier, we have leasehold and lease commitments on approximately 15,000 acres in Carroll County and have closed on approximately 13,700 net acres, with the remainder expected to close during the first quarter.

Depicted on this slide, this is the first time that we have disclosed our acreage position in Carroll County, and the close proximity roughly 1 mile away, from the 2 Chesapeake discoveries that were announced earlier. You can also see 5 other Chesapeake completions adjacent to our acreage. As we stated before, acreage position in Carroll County allows us the opportunity for 100 net drilling locations.

We continue to lease acreage to fill in or to increase our working interest in perspective units. We're expecting to spud the first of these 2 wells in April of this year and are working with Dominion East Ohio to connect our well to -- wet gas sales upon completion. We should have results from these wells available for our second quarter conference call in August.

Moving to Slide 13, we have an update on our ASP projects in the Illinois Basin. Production in the Middaugh pilot continues to respond as expected, and we continue to be encouraged by the results.

As of year-end 2011, we have booked proved developed reserves in the Middaugh pilot and Perkins-Smith project areas at approximately 13% of pour volume. This recovery factor equates to approximately 31.5 million net barrels of resource potential across our acreage perspective for treasury recovery using ASP.

We currently have identified 27 separate target areas, with another 1,900 acres undergoing further review. As we have mentioned previously, with full ASP development of the 58-acre Perkins-Smith area and the high-impact 350-acre Delta unit, we have the potential to double current production from the Lawrence Field in 2015.

And with that, I'd like to open up the phone lines for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Neal Dingmann with SunTrust.

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

A couple of things. First, just on Utica. You mentioned before about potentially some bolt-on acquisitions, other things. Tom, where does that sit now? I mean, are you still -- these are some things you're looking at all? Or should we think about this maybe the $15,000 for the most of the year in Ohio?

Thomas C. Stabley

Yes. In Ohio, really, what we're doing there is similar to what we're doing in Butler, which is continuing to fill out the units, work on increasing our working interest in all the wells that we're going to drill there. So it's not going to be a material change in the way or prospect for this year, but you should see some acreage as we continue to bolt up and block one of those existing units.

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

Okay. And then looking at -- moving over to Butler on some of your operated wells. That's just one on location-wise, will you continue to delineate some of those? I mean, I'm kind of looking at the map versus the where the growth section on some of these others have been drilled. Is that kind of the plan this year? Or potentially, going forward, do you start pad drilling at a certain point? So I just kind of wanted your thoughts on that.

Patrick M. McKinney

Yes, a good question. I mean, I really think the theme for this year and even partially for next year is we still are picking units to drill to hold acreage that's in a potential position to expire. I think, though, as we've kind of indicated, we can drill wells to all 3 zones or prospectively 4 zones in hold acreage. So in those wells that we are drilling to hold acreage, we're going to be selective and try to continue to test Burkett on occasion or now this year the Rhinestreet to go and really get more color on the Upper Devonian, and as well, too, as you saw, the Utica wells that we were going to drill, they were going to hold acreage at the deeper depths. So we swap them out, and we're going to drill some shallower wells with that. So it's still more or less an HBP-type program, but we do have flexibility to test different zones within those units.

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

And then just lastly, if you could, just overall, what do you see in kind of now going forward on just overall completion costs, all service costs? And how you see that sort of playing out for the year?

Patrick M. McKinney

Well, obviously, with most operators announcing some sort of reduction, especially in central and eastern Pennsylvania on the dry gas side, there is some that's available. We feel good with our service provider, Frac Tech. We feel good where we're at with the pricing, and it reflects more of the market-based pricing. And I think the other completion services, which you're starting to see, is perhaps -- as opposed to a reduction in day rates, you're seeing reduced other ancillary or accessorial charges like standby and other things come down. So we're very confident we can hold the line on costs and hopefully, take them down to be able to report some of those results as we get later in the year.

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

And then one more, I apologize. A little bit -- I know you don't give maybe a specific just on cash, but maybe could you just comment about, clearly it appears that your sales revenue per the liquids or the oil continues to increase, albeit from a pretty small base but continued to increase nicely. Maybe just put a general comment around that, how you see that going forward.

Thomas C. Stabley

As far as the percent of our liquids, we ended the year, on an exit rate, about 28% liquids, oil and NGLs. I think once we get into the Utica and we see what those wells are fully capable of and the results out of that area, I think we'll have a better indication of where kind of that mix is going to change as we go through 2012. But with the majority of our wells coming out of Butler, we should easily be able to maintain at least that 28%. And hopefully with the results we see in the Utica start to turn that and continue to increase it.

Operator

Our next question comes from Leo Mariani with RBC Capital Markets.

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

Guys, it looks like you're going to have...

[Technical Difficulty]

Operator

Our next question comes from Ron Mills with Johnson Rice.

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

Questions related to a couple of things, actually. You mentioned the Butler County activity in relationship to Ranger is super rich. The area that they identified is superrich in their presentation today. How far away from their superrich window are you located? And in any of your wells that you've produced, have you seen any kind of the richness in the gas stream, the 1,350 BTU-plus that they have used to be called the superrich area?

Patrick M. McKinney

Well, Ron, I mean, just looking at where they put that line and they would be in about 1/3 of our Butler acreage on the northwest corner. We haven't drilled or completed any Marcellus or Upper Devonian out there. Obviously, 2 of the wells that we're targeting are going to be up there. The only well we've got up in that quadrant is our Cheeseman well, which went down to the Utica. So the current 2-well Plasniak pad that we're drilling now would appear to be in that window, and we're going to go through and test up there and see if we can confirm that -- where that line is.

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

Okay. And something else in their presentation. I know you've had some legacy acreage ever since the IPO days up in northwest Pennsylvania, the Venango, Mercer County area. They have, in today's presentation, highlighted that area and talked about both Marcellus and Utica potential. Do you still have that acreage? Is it all held by production? What's the status of that acreage?

Thomas C. Stabley

Yes, Ron, it's -- we have approximately 3,600 acres in Mercer on the western side, and that acreage is HBP, and then we have an additional, I think, it's approximately 9,000 acres in Morrow Country and again, all of that is HBP. So we do have -- we still have that acreage in those areas.

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

And Chesapeake on their conference call talked about a couple new wells today, the Burkett and the shallow wells, which relative to -- in the Utica, which relative to your Utica presentation, both those look like they're within 1 to 2 miles of your acreage, pretty strong results. What -- I see where your first 2 wells are. What's driving your first couple of locations? And is there any thought to maybe even drilling closer and maybe benefiting from a reserve booking standpoint from Chesapeake's activity?

Patrick M. McKinney

Ron, this is Pat. It's kind of hard to book pads off somebody else's wells. But I think to be sure, it's very encouraging there where acreage lines up against Chesapeake's drilling activity. I would just tell you, our first 2 locations were picked, obviously, on access to the Dominion East Ohio line. Obviously, they let it clear to get in there quicker and a few other logistical standpoints. But we feel that the geology doesn't change much from really through our acreage across there, so we feel we were trying to be as close as possible to some of Chesapeake's wells to have some well control. But it will be interesting to look at the results that he reported. He's obviously aware of, on the call here this morning, if you go look at it. I mean, we've said all along. We feel our acreage in Carroll County really is "ground zero" to the results that he's reporting.

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

My question on the bookings was if you can drill some on your acreage offsetting those wells, potential for some in-fill bookings. I mean, my understanding, they get comfortable if you have wells and others have wells offsetting you in terms of bookings and then field locations.

Patrick M. McKinney

Absolutely, Ron. I mean, that's going to add a lot of color and credibility to when we drill our wells to be able to look at maximizing our pad bookings on our acreage. So there's no question that's going to help this whole process for us.

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

Okay. And then one easy one for you, Tom. On the liquidity standpoint, in the presentation you walked through your current liquidity. You have $50 million available on the term loan. And was it $150 million available on your revolver? Is the plan to drawdown on your revolver first, which is lower cost, or what's -- what would cause you to dip into that remaining availability under the term loan?

Thomas C. Stabley

I think, obviously, the lower costs firstly would be our first choice as we go out to the development plan for this year. Secondly, it was really put in place and that additional availability was there in case we were able identify an acquisition or a transaction that would be accretive to the company in its current Appalachian Basin area. So that's kind of what that's in place for, Ron.

Operator

Our next question comes from Leo Mariani with RBC Capital Markets.

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

You guys are obviously going to exit 2012 with a pretty significant backlog of wells in the Marcellus in terms of wells waiting to be frac-ed and wells waiting to be hooked up. What type of gas price do you think you guys want to see you before deciding to go ahead and bring those wells on production?

Patrick M. McKinney

Well, Leo, I mean, we're going to have 13 wells awaiting completion, and I think it's consistent with our theme that based on what we see in prices that, obviously, we can go in and in the second half of the year look at frac-ing those wells. But we feel our plan now kind of represents this level of pricing to go through the year. And obviously, based on the results of what we'll see in Ohio and based on what commodity prices, we think this gives us a lot of optionality if we do want to go and frac those wells during the tail-end of this year, bringing on that production to price more.

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

Is there any kind of bogey you guys are thinking about in terms of price? Is it $3.50 or $4? How are you going to think about it?

Thomas C. Stabley

I think, Leo, again, it's going to really depend on what we see in the Ohio Utica and the results there. It's going to be an allocation of capital to the highest return areas and based on keeping the plan full in different components. So I don't think we have a specific price identified at which we're just going to turn the switch.

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

Okay. And in Westmoreland, it looks like that latest crop of wells that you guys had were pretty significantly above your 4.2 Bcf type curve. Anything that you did differently with those particular wells you think it might have led to stronger production performance over the last 60 days?

Patrick M. McKinney

Well, I think what Williams has really looked to doing is getting consistent on where their landing the wells and also, just getting more sand in the ground, very similar to the learning curve that we went through in Butler. They've been able to go and execute in Westmoreland and looking at shorter cost or stages and shorter spacing between the fracs. And you're exactly right, they -- to your end, a lot of those wells were curtailed, and we booked them at 4.2 Bs. And these 60-day rates would tend to indicate that those EURs have be a lot of room to rev up.

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

Okay. In terms of your acreage in Butler, what percentage right now is HBP?

Thomas C. Stabley

That number right now, as it stands, and I would say with the current program that we have in place this year, would be somewhere in the vicinity of about 25%, 25% to 30% of the total.

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

Okay. That's after your drilling program this year?

Thomas C. Stabley

For 2012.

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

Right, okay. And just kind of going forward, I imagine you guys have a multiyear plan to hold that. Is that kind of 1 to 2 rig program for the next couple of years would hold that acreage?

Thomas C. Stabley

Yes, we think with a 1 rig program and the addition of a top-hole rig that we could get through and hold the majority of that acreage.

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

Okay. And obviously you guys, in conjunction with your partner there, WPX, are slowing down in the dry gas area. Is there any concerns about potentially losing any acreage there as a result?

Thomas C. Stabley

We don't see that as an issue in 2012. We do have some commitments in '13 that would require us to get back in and drill some wells or perhaps look to get some additional lease extensions. Some of those leases were taken early on in the Marcellus process by Rex, and so a lot of them do have extensions, so we can take a look at either the extensions or getting back in and drilling. But we will have some wells to drill in '13.

Operator

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

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

You alluded to this earlier, but I just wanted to explore a little bit more. I realized you haven't even drilled your first well in Carroll County yet. But if you do get the results that you're hoping there and say, Chesapeake's wells continue to look good, what could you do there in terms of ramping up beyond the 2 wells that you've got to play so far?

Patrick M. McKinney

Mike, this is Pat. I mean, we're in the process of really trying to lay out the units out there and kind of work towards getting drilling permits to give us the optionality to really go at any kind of pace we would like. I mean, obviously, gas sales are important effect that we've got firm transportation on Dominion Ohio East, helps that cost. We don't want to drill wells that's random, so we're really trying to go and have a balanced approach, drill the first 2 wells, frac them, talk about the results. And as you said, if Chesapeake continues to have great well results, I think, our storyline this year is to have optionalities as we get into the second half of the year to really ride the wave of the results that we see.

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

So there's definitely some potential to ramp-up there, it sounds like.

Patrick M. McKinney

Yes.

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

Okay. Maybe a follow on Leo's question. On the backlog of those 13 wells in Westmoreland, is that going to take some additional infrastructure to bring those on, too? Or is it just strictly the completion economics that you're looking at in terms of whether to go forward with those or not?

Thomas C. Stabley

They do have some additional infrastructure and capacity available on the east side of the field, which is where some of those wells are. So they could get those wells into sale. But obviously, as you have some decline on the existing wells, then they'll be able to put those into sales, if that decline falls off. But I think for the most part, if they frac them all right now, I don't think they could get them all into sales. But as they space them out over the next -- into 2013, they shouldn't have any issues.

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

That makes sense, okay. And also looking at the well performance on the Butler County wells, have those been experiencing constraints with the processing capacity that you're bumping up against?

Patrick M. McKinney

Yes, Mike, that's a good question. The rates that we reported earlier on the McElhinneys and on the first 3 Grosick wells, those wells were curtailed. Now that we've got the Voll Compressor Station up and have the capacity of 40 million a day, we should be able to let those wells go. But I would probably tell you, over the last 90 days, a majority of almost all of our wells had really some part of curtailment on them. So when we report rates of around 3 million a day, those did come with some pretty high pressures as those wells were choked back.

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

Okay. And then the Bluestone Plant, you said it's commissioned in May. What's the timeline to ramp that up? When would you think you can get the full capacity on that?

Patrick M. McKinney

Well, I'll just tell you what happened with the Sarsen Plant when it came on in December. It really took us about 45 days to get up to its capacity. And I would expect it's going to take the similar type of ramp where you're going to bring wells on, they're going to check their systems out and continue to bring more wells on. So for planning purposes, you could probably assume sometime in the third quarter will be -- have line of sight to really what that plan will do. But it's going to take at least 45 days to 60 days to really go and ramp that up.

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

That's helpful. Then the last one, then I'll get back in the queue. Any update on the midstream sale with a lower budget? Does this kind of take the pressure off of doing that midstream sale this year? Do you still think that's going to happen?

Thomas C. Stabley

I'll answer the first part and then the second. The midstream sale continues to progress, as we mentioned before. Both the Rockies assets and the midstream assets, we expect to close in the first half of this year. Again, you're going through a fully marketed deal so you've got the data rooms and then ultimately, they want to meet with management here at Rex since we're a big part of it. So those processes are continuing on. But certainly, the equity raise and the reduction in the capital budget takes some of the pressure off, making sure we get the right partner in Butler County. And we've said that all along that, that was an important part of this process, is that we get a partner for the future for Rex in developing this area and eliminating or continuing to eliminate any of the midstream issues that we've had.

Operator

Our next question comes from Ron Mills with Johnson Rice.

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

Pat, you mentioned earlier in Westmoreland that you have the 30- and 60-day rates were outperforming that 4.2 type -- Bcf type curve by 40% to 55%. Are you seeing similar type of results on your Butler County area? And how much of that do you think is driven by these wells coming on at constraint rates, if at all?

Patrick M. McKinney

Yes, Ron. I mean, I think as we just mentioned on the call, we're really being constrained for the last -- out in Butler, the last 60 or so days as we continue to bring wells on. I think we feel really good about our type curve in Butler, but that's not to mean that we don't think there's room for improvement. I would really like to see these wells produce for a period of time and see what the decline curve is and really see what the shape of that curve is as we get out. I mean, obviously, in our standard 3,500-foot lateral that we go and that we named the EURs off of that, we do have wells that are significantly higher than the 5.3 Bcfe out there in our portfolio that are PDP wells. So again, we're trying to standardize the cost and the lateral length. But we're still very optimistic that we can work to take that curve up as well, too.

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

And can you refresh our memory? Are the new type curves, were those based off of the reserve bookings from your engineer at year end?

Patrick M. McKinney

Yes. Yes, it is a type curve well for a 3,500-foot lateral 12 stage frac.

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

Okay. And then from a booking standpoint, is there any appreciable difference in terms of the way they book the pads versus developed with locations in terms of EURs?

Patrick M. McKinney

No, I mean, it's -- they're actually booked, Ron, on a reserves per lateral length or treated foot. So if you have a 4,200-foot lateral, it gets booked at that rate based on the length of the lateral.

Operator

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

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

Just a couple of follow-ups. The 7 wells that in Westmoreland you said were outperforming, what was the cost on those?

Patrick M. McKinney

Yes, we've not really gone through and looked at a lot of costs. I think in the economics, we put out there, Mike, that there are roughly $5.8 million, again, for standard lateral length, 3,500-foot lateral length.

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

Were those wells longer lateral length? Or were they similar to what you've been doing?

Patrick M. McKinney

They were a little longer. And so obviously, their cost on the increased footage was more. But again, they were booked pretty much on their deliverability per lateral length foot.

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

Got it, okay. And then in terms of the Rhinestreet, how far away is that and the strat column from the Burkett? And would you expect to get contribution from both? Or do you think they're going to be separate?

Patrick M. McKinney

Well, it's going to be 400- to 600-foot higher in the strat column. And you've got the Genesee between it, as well as the Tully [ph] there. So it looks like the break is, the Burkett or Oltreat [ph] kind of on its own, and then when you get into the Rhinestreet, it's a thicker section, Mike. So it's about 150-foot thick. And so you probably-- if you did a break, you'd break at the Burkett and then you'd have the Genesee and Rhinestreet up above it where you have -- what we like is it's a thicker column, and it's strat a little higher, so the potential to have higher liquids concentration is there for that.

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

Okay, great. And last one on the NGL prices. What are you seeing currently versus WTI for, say, propane, butane? And how does that compare to, say, Mont Belvieu prices right now?

Thomas C. Stabley

Well, the pricing that we had in the fourth quarter was about 58% of NYMEX. It is, as you recall, our liquids mix there is not -- does not contain a significant amount of ethane. The ethane that we withdraw there at those plants is used to burn in the compressors. So the majority of our Y-grade and the propane that we sell does not include a lot of ethane. So with this recent decrease in ethane prices, that shouldn't have a significant effect on our existing Y-grades.

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

And in terms of -- I mean, NGL prices in general, though, with even propane come down a little bit, it's that correct, since your fourth quarter?

Thomas C. Stabley

They have some. I would just say in addition to that, that our propane is sold into some local markets, so we do get a little bit of a premium over some of the stuff that's going out to the other plants.

Operator

I'm not showing any other questions in the queue at this time.

Thomas C. Stabley

Okay. Thank you all for participating in Rex Energy's fourth quarter year-end conference call. And we'll look forward to seeing you on the first quarter call. Thank you.

Operator

Thank you. Ladies and gentlemen, thank you for your participation in today's conference. This does conclude the conference. You may now disconnect. Good day.

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