Rex Energy's (REXX) CEO Thomas C. Stabley on Q4 2014 Results - Earnings Call Transcript

Rex Energy Corporation (REXX) Q4 2014 Results Earnings Conference Call February 19, 2015 8:00 AM ET

Executives

Mark Aydin - Manager of Investor Relations
Thomas C. Stabley - Chief Executive Officer and Director
Patrick McKinney - President and Chief Operating Officer
Thomas Rajan - Chief Financial Officer

Analysts

Leo Mariani - RBC
Neal Dingmann - SunTrust
Ron Mills - Johnson Rice
Jeff Grampp - Northland Capital
Kim Pacanovsky - Imperial Capital
Marshall Carver - Heikkinen Energy Advisors

Operator

Good morning, ladies and gentlemen, and welcome to the Rex Energy Corporation’s Conference Call to discuss the company’s Fourth Quarter and Full Year 2014 financial and operational results. At this time, all participants are in a listen-only mode. Later in the presentation, we will open up the phone lines for a question-and-answer session and instructions for the question-and-answer session period will be given at that time.

I would now like to introduce Mark Aydin, Investor Relations.

Mark Aydin

Good morning, and thank you for joining us for the Rex Energy's fourth quarter and full year 2014 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, Thomas Rajan.

Today’s discussion will include forward-looking information and references to non-GAAP financial measures. Please review our cautionary statements in the release and accompanying slide presentation. In addition, you should refer to the disclosures in our 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 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 will now turn the call over to our Chief Executive Officer, Tom Stabley.

Thomas C. Stabley

Thank you, and good morning. I hope you’ve all had a chance to review our fourth quarter and full year 2014 results. I’d like to begin the call this morning by going over a few key points that I believe are of the utmost importance to Rex Energy. I’ll start by reviewing our updated well-level economics for the Butler Operated Area.

On slide 3 you can see the evolution of our Marcellus EURs and many enhancements we have made over the years, especially since we have started our reduced cluster spacing or RCS completions in 2012.

For 2015, we are projecting an EUR for our Butler Operated Area of 15 Bcfe, which is a significant increase over our year end 2014 EUR of 11.7 Bcfe. As the slide shows, the continued improvements in Marcellus EURs are due to various different factors; while we are still averaging 5000 foot lateral lengths and continuing to utilize RCS fracs, we have made adjustments to the completion design which is allowed us increase EURs.

In 2014, we averaged approximately 1800 pounds of sand per foot. In 2015, we are now averaging 2200 to 2500 pounds of sand per foot, which has had a dramatic effect on the initial 30 day IP rates and resulted in shallower declines, which positively impacts EURs.

In addition too, our operational and technical teams continue to realize and gain strong operational efficiencies in the Butler Operated Area which has allow us further reduce our well cost to approximately $5.5 million, down from year end 2014 well cost of approximately $5.7 million.

Slide 4, gives a more detail look at the effects of increase sand concentrations on our RCS wells that have been on production over 1 year. As you can see on the chart, we have our 11.7 Bcfe type curve and our 15 Bcfe type curve, with the dots representing both Marcellus and Upper Devonian wells, these wells have been adjusted to 5000 feet, but have not been adjusted to account for the increased sand concentrations we will be utilizing in 2015.

As you can see, the large majority of the wells are trending at or above the 15 Bcfe type curve, without the added effects of increased sand concentration. The majority of these wells were completed utilizing approximately 1600 to 1700 pounds of sand per foot. We believe that when we start seeing more results of wells completed with the increased sand concentrations, the wells will be trending above the 15 Bcfe type curve.

On slide 5, we have our updated Butler Operated Area of Marcellus type curve, rates of returns, well cost and pricing assumptions, as well as a comparison to these metrics as of year end 2014. The focus of this slide is the increased rate of return we expect to see in 2015 despite a challenging commodity price environment.

The continued improvements in the Marcellus well level economics are due to a number of factors. We have maintained our 5000 foot average lateral lengths in the Butler Operated Area, while also reducing our well cost by an additional 3% to $5.5 million from the year end 2014 well cost of 5.7. I would also like to point out, that the $5.5 million well cost is fully loaded and assumes a 4 well pad cycle time; again, these are not single well economics.

Second, our operational and technical teams continue to realize strong operational efficiencies in the Butler Operated Area. As we mentioned, before we have been able to increase the type curve and improve economics by making adjustments to our completions designs which have had a positive effect on our EURs and rates of return.

Third, we have locked in approximately 85% for 2015 of all production that was previously sold at Dominion South Point at $0.80 off of Henry Hub gas price for 2015. This has had a positive effect on our rates of return as previously we were assuming a dollar differential. All of these factors have led us to increase our rate of return in our Butler Operated Area in spite of the challenging commodity environment we are all facing.

Assuming our low case scenario of $3 NYMEX and $60 WTI, we have increased our rate of return to approximately 21% from year end 2014 of approximately 11%. Assuming strip pricing, our rate of return increases to 27% from 17% at year end 2014.

I'd also like to point out, that in addition to our improvements in EURs, we were also successful in 2014 with our test of 650 foot down spacing, which is resulted in taking our growth potential drilling locations from 1266 gross locations at year end 2013 to approximately 1520 gross locations, a increase of approximately 20% year-over-year from 2013.

Lastly, I'd like to finish up with a few brief comments regarding Rex Energy's liquidity position, which Thomas will take you through in more detail. Rex Energy entered 2015 with approximately $420 million of liquidity and we are actively looking at various enhancements to our position.

As we have stated before, we are currently pursuing joint venture partners in our Moraine East area. In addition, we have engaged RBC strategic advisor to pursue the monetization of our 60% ownership in Keystone Clearwater solutions. We believe the completion of either or both of these transactions during 2015 will provide us with ample flexibility to execute on our joint plan during 2015.

With that, I'd like to turn the call over to Chief Financial Officer, Thomas Rajan.

Thomas Rajan

Thanks, Tom. I’ll be focusing my comments this morning on liquidity position. On slide 6, you can see our capital structure going into 2015. Our current cash liquidity of $20 million, plus availability on our bank line, proceeds from the sale of Keystone partnership and the joint venture for Moraine East, all enable us to fully fund our capital expenditure program this year.

During the fourth quarter we were able to work with our bank group to replace to the total debt leverage covenant with a senior debt leverage covenant of 1.75 times TTM EBITDAX. As of December 31 2014, we had outstandings under our credit facility. Our primary focus at this time is a securing a JV partners for Moraine East and monetizing the Keystone business.

We are moving forward with both paths, and expect to announce additional status in the first half of 2015. In addition to these two areas of focus, we have other leverage we can pull to further enhance liquidity, which includes the potential sale of our non-operated position in Westmoreland, Centre, and Clearfield Counties, PA.

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

Patrick McKinney

Thanks, Thomas. Moving to slide 7, I'll focus my comments on our Moraine East area and the current state of our development plan, and the results of preliminary analysis we've conducted. We are currently drilling the third of four wells on the Renick pad. This pad has three Marcellus wells and one Upper Devonian Burkett well, with lateral lengths averaging 5820 feet.

The Renick pad is depicted on the map in blue which represents a area in which Rex's anticipates drilling 10 to 16 wells in 2015. Similarly, we show that 2016 estimated drilling plan for the Moraine East in green and lastly the 2017 drilling plan in brown. All told, we only need to drill 44 wells during this timeframe to hold approximately 80% of the 45,000 acres in the Moraine East area.

The preliminary log and petrophysical data we have gathered from the Renick pad is been very encouraging and supports our initial interpretation in the Moraine East area is been consistent with the core of the core as compared to our legacy Butler Operated Area. We anticipate completing the Renick wells in the second quarter of 2015 and having preliminary flow back test results around same time.

The wells we replaced into sales during the fourth quarter of 2015, after the gathering and pipeline infrastructure is completed to the MarkWest Bluestone complex. For 2015, as mentioned previously, we anticipate drilling 10 to 16 wells and completing 4 to 10 wells in Moraine East area.

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

Question-and-Answer Session

Operator

Thank you. [Operator Instructions] Our first question comes from Leo Mariani with RBC. Your line is open.

Leo Mariani

Hey, guys. I was hoping you could maybe fill us in on a little bit more detail in terms of where you guys are at specifically with regard to some of these asset monetizations. I know you announced some of these efforts in the second part of 2014.

So just trying to get any additional color you can sort of give on timeline, whether or not you've already accepted bids for the water business or anything you can add would be helpful?

Thomas C. Stabley

Certainly. Hey, it’s Tom. So on the Keystone process, the preliminary indications in this process have been strong. We're pleased with where we're at in the process. We expect to be actively in the market during the remainder of first quarter and it’s a second quarter event for us to potentially close a transaction on Keystone.

On the Moraine East activity, we obviously since year end have completed drilling the first two wells which have given us log data in the area. That allows prospective partners to see the direct correlations of the geology between the legacy area and our new Moraine East area.

We are currently in conversations with both strategic and financial partners for this area, and again expected to be a transaction that we look forward to during the second quarter. So both of these transactions are in various stages of negotiations, but at this point we're very pleased with where we are and it will be a second quarter type transaction for Rex.

Leo Mariani

Okay. I guess, do you guys feel as though you'd like to execute both deals or sort of one of the two. Could you maybe just kind of speak to what your ultimate goal would be?

Thomas C. Stabley

Yes. I think for Rex, we set out of with goal of executing both transactions, that still remains the plan. I think both of those transactions with Keystone and the joint venture partner sure up the balance sheet and put us in a position with the liquidity that we have in hand to fully fund 2015 and well into 2016. So that’s our objective and we feel comfortable with where we are in this process.

Leo Mariani

Okay. That's helpful. I guess, with respect to your expectations for materially better performance in Butler, sounds like you guys are putting quite a bit more sand into the wells. You guys sort of described it as kind of a projected EUR of 15 Bs in 2015.

Are you seeing enough preliminary data on some wells where you added a lot more sand here, where you feel as though you're already seeing that on some of the early 2015 wells? Can you just kind of help us kind of bridge the gap between the year end 2014 EURs and sort of what you're expecting this year?

Patrick McKinney

Hey, Leo. This is Pat. That’s a great question. We work with NSI – NSAI, or Netherland, Sewell, to really go and look at the well performance as we continue to take the sand concentration up and the performance of our RCS wells. We've had a number of longer performance in PDP wells that have already performed above the type curve of sand concentration at or below 1800 feet. We've even got five legacy PDP wells that were to drilled average lateral lengths of about 4000 feet with sand concentrations of about 1500 pounds that have actual performance trending above even a 13 Bcfe average.

NSAI has agreed with our methodology to model these, but obviously they want to wait and see actual well performance in excess of six months before we can actually put PUDs at these higher levels. But we expect that we'll have the actual performance, plenty of it by the end of 2015 to confirm these.

In the second half 2014, we fracked 20 wells at sand concentrations of around 2000 pounds per foot and today we fracked an additional nine wells that have sand concentrations at or above 2300 pounds, and all these wells were drilled above 5000 feet.

So we think we're going to have a great inventory of wells to be able to prove this and ultimately get it done before year end, but we think we'll have a great data set to be able to prove this. And as I mentioned, we've seen it on legacy wells that were RCS, but at much lower sand concentrations.

Leo Mariani

All right. That's helpful. On the 15 Bs, can you break that down for us in terms of just components by hydrocarbon, in terms of gas, C3+, ethane, conde [ph]?

Patrick McKinney

Yes. I mean, really you're taking the same curve as you could see from those lines Leo, you've got a higher IP rate, which obviously gets your gas component up. So our splits for C3+, C2 are in the same proportion as we've had before, but we're taking a gas side of the Bcfe up from about 6.5 Bs to close to nine Bs on just the gas side, gross, those are all gross numbers.

Leo Mariani

Okay. That's really helpful, guys. Thanks.

Operator

Our next question comes from Neal Dingmann with SunTrust. Your line is open.

Neal Dingmann

Yes. So, Tom, for you or Pat, just wondering, on that projection that you have, I think I forget which side it is, which shows is just – the year end 2014 and then the 2015 target. The all-in well cost, guys, is that the $5.5 million, what are you assuming there on sort for service cost declines, and again remind me, I guess, that's – with that $5.5 million, does that – that includes the higher costs for the increased sand or just walk me through what's in that?

Patrick McKinney

Yes, Neal, that’s great question. So, at year end we've got down to the 5, 7 which was primarily driven mostly by service cost reductions. And as we mentioned in the Appalachian Basin, it was really not a basin that had a lot of inflation to begin with anyway. So, like other operators in the basin, we were seeing this between 4% to 6% reduction in service cost.

And then the rest of the way home, we're going to get it through operational efficiencies. We haven’t talked a lot about what we've done on the drilling side, since I think we reported our Marcellus were averaging 15 days back a couple of quarters ago. We've continued to go and knock that number down and that we're averaging closer to 12 days for the same, the same lateral length that we reported previously. So, we think we can get the rest of the way home on drilling and completion efficiencies.

Neal Dingmann

Got it. Then I know, I forget if it was in this last release, the one before that. Tom, can you guys talk a little about just price realizations, I know for what the remainder of this and I was thinking more into next year, how you all are set. I know you have more locked in FT than you've had in a long time.

So I'm just wondering when I look at the price realizations that you had just in this most recent quarter or looking in 2014 average overall, just your thoughts on how that will compare versus Henry Hub for 2015 or 2016 versus the prior year?

Thomas C. Stabley

Yes, I think if you look at – in the corporate presentation we have slide on price utilizations for Rex and I think one of the things we focused very diligently on in the second half of 2014 and right to the widening of a differentials to Dominion South Point in our overarching exposure to South Point in local basin pricing we went out and we're able to get the majority of our gas production locked in at about $0.80 below Hub. So those are conversions that we made, both through financial and physical contracts on all of our existing agreements with our purchaser.

So for this year, we would expect to be in that $0.80 range. I would tell you that our percentages are little bit heavier in the April through September or October timeframes. So we're able to benefit for instance during this month and even potentially in March where as we sit here today gas is actually trading at Hub with really no differentials at South Point.

So I think we're going to benefit a little bit more in that during the first quarter and the fourth quarter, but really protecting is high as 90%to 95% during April through September which is where the basis tends to blow out the most.

Neal Dingmann

Okay. And then just lastly, Tom, for you or Thomas, just on that slide on the liquidity and the capitalization slide, I mean, to me it looks like even if I have just a minimal outspend this year, even with or without the two deals that they do, obviously it would be great if they can both go through, but even if they – let's say worst case they don't, you still have to me I'm looking at just that total liquidity, still looks like by year end 2015, you'd still have more than adequate liquidity. Am I correct there?

Thomas C. Stabley

Yes, you are correct.

Neal Dingmann

Okay. Thank you all.

Operator

Our next question comes from Ron Mills with Johnson Rice. Your line is open.

Ron Mills

Good morning, Tom.

Thomas C. Stabley

Hey, Ron.

Ron Mills

Question just on the ATEX and the compression impacts during the first quarter. Can you provide a little bit of color how much was related to each of those and whether or not you were able to give away or just sell some of the ethane related to the ATEX rupturing and still maintain some of that value?

Thomas C. Stabley

Yes. Thanks, Ron. So the outages during the first quarter as relates to those two, a little bit less than half is ATEX. On the ATEX side obviously that line is back up and running. We were able to, as you all know, we can't really flow above 1100 BTUs without a waiver and there's really no other outlet for the ethane. So we did achieve that, that waiver that was necessary.

So at the present time ATEX is back up and running. We're actually currently still flowing a little bit of additional ethane on the gas side, as opposed to putting in any ATEX line, simply because the pricing as the gas realization is a little bit better than the ATEX side, so we'll continue to do that probably for about another month and then we'll be back up to our full 3000 barrels a day starting April 1st at ATEX.

On the Ohio side in Warrior North, the compressor station is expected to be back up in running here probably within the next two weeks. We have been able to do some work around to be able to flow gas around that compressor station, so we're in about 50% right now and would expect to be back up to full strength here in about two weeks. So, both situations should be resolved by the middle of March, no later than the end of March.

Ron Mills

Okay. And then as it relates to I mean, the water solutions and Moraine East have been talked about, but as relates to the non-op Westmoreland County, I know that's another lever you guys can pull.

Would that be something that you would look to potentially – could you even look to sell that even if Williams didn't want to sells theirs, because I know there have been thoughts maybe if they wanted out, too?

Thomas C. Stabley

Sure. We certainly have active negotiations with our partners there. I mean, they have their objectives as well. If there is a chance for us to partner, something we would certainly strongly consider. But on a non-op basis there are groups out there as we've indicated in the past, for an asset of this caliber, that’s predominantly HBPed that would look for something like this.

So it’s a very good asset. I think it’s a little bit economically challenged probably in a $3 gas environment, but with the majority of it being HBPed, it certainly has good quality as a go forward basis. So it’s something we could monetize as a non-operated position as well.

Ron Mills

Okay. And then lastly, maybe for you, Pat, just as relates to the Renick pad, I know everything looks really encouraging or similar, and even NSAI seemed to agree. But when you talk about finishing the drilling of the four wells and then having test results in the second quarter, is that when you expect to complete the wells or when do you expect to provide the data, the results, the well data to us?

Patrick McKinney

Hey, Ron. Yes, that’s great question. So, we went in and drilled the first well, went in and got a little bit more intense log suite package, as well as some sidewall cores on the first well and we've had a chance to analyze a good chunk of it.

And first off, what we've really seen is the continuation of what we call our Butler core trend on the porosity and permeability side and we were pleasantly surprised that the Upper Devonian Burkett actually looks a little thicker section with some better porosity.

So that’s really given us a lot of comfort. The preliminary core result data, while it's coming in a little bit slower, really confirms a lot of the petrophysical things we've seen in the log. So we're very, very encouraged from what we've seen. And we have a very tight correlation to a lot of these metrics to actual well performance. So, that gives us a lot of comfort.

On the timing, we're going to go through and actually frac these wells. We are coming up in April and we'll probably do a limited flare test and with some back pressure to try to go and get what would be normal comparison rate, other rates that we put, probably get a very good five-day rate on it.

And then as you know, since we're going to go into Bluestone complex from those wells, but we actually have to go through and construct the gathering and the trunk line to get those wells into sale. So we're probably looking at a fourth quarter type sales, actually putting those wells into sales.

Obviously we'll continue to drill up there, so as other wells get completed we're looking in the fourth quarter, we hope to be able to bring those on as well too. But we won't have sales from these wells till probably the fourth quarter.

Ron Mills

Great. Thanks. And great quarter. Thanks.

Thomas C. Stabley

Thanks, Ron.

Operator

Our next question comes from Jeff Grampp of Northland Capital. Your line is open.

Jeff Grampp

Good morning, guys. Just I guess, I wanted to go back to the upsize profit and concentrations and obviously seeing some great results even without that relative to the 2015 B curve.

I was just hoping maybe to get an update on performance of the wells where you guys have had the upsize proppant, and maybe just comparing that to where things look to that 15 Bcf curve?

Patrick McKinney

Yes. Jeff, this is Pat. On lot of the wells that where we're starting to get some preliminary well information on the – out of the subset of 20 wells that were at 2000 pounds. And I think what we're seeing from those is, we're seeing the higher initial IP rate, we're seeing the shallower decline. So that gives us a lot of comfort that we're going to sit on that curve.

Obviously as we continue to get longer laterals lengths, that's going to go and really buttress that number. Some of the other older vintage wells were not all drilled out to at least 5000 feet. We started to approach all the wells averaging 5000 or more now, so that’s going to – the lateral length has a driver on that as well too.

We've got some wells now that we' in the process of completing here in the first quarter, like the Powells [ph] is four-well pad where we got longer laterals that really did frac jobs off on those.

So, I would start to look for some of those well results probably in the second quarter and we'll note the wells in the same concentrations on that we could really see some of these increased type IP rates.

Jeff Grampp

Okay. That's really helpful. And then I guess, you kind of transitioned to my next question on the lateral lengths. Have you guys kind of earmarked what maybe an average lateral is on the 2015 program at this point, or is it still kind of in flux given we're only in February at this point?

Patrick McKinney

Yes, Jeff. We're trying to target all of our wells now to be at least 5000 feet. Obviously as we mentioned before the lease lines and the unit sizes kind of drive that in some cases, but our line department has done great job, and given us a lot of runway out there on all of our pads going forward to be in excess of 5000 feet. I think we'll average 5500 I think this year.

The one key thing in the Moraine East area, while in the slides you can't see the actual unit designations, since that was more of Greenfield set up for realization [ph] all of our wells for the Moraine East area should average closer to 6000 feet in that area. So we're really excited about being able to go in and start to consistently drill some longer laterals than the 5000 we show in our reserves or economics now.

Jeff Grampp

Okay. Great. And then I guess, last one from me. If you guys could share maybe some sort of EBITDA or cash flow number on the Clearwater asset. Is there like a 4Q number you guys could share for that, just to kind of give us a sense for a run rate there?

Thomas C. Stabley

Yes. I think the EBITDA for this year – year end for Keystone Clearwater for the full year 2014 was about $40 million, $50 million for full year. So obviously Q4 was going to, on an annualize basis, its going to put you well above that 50.

Jeff Grampp

Okay, got you. And Tom, is that net to the 60% or is that on a 100% basis?

Thomas C. Stabley

That’s on a 100% basis, yes.

Jeff Grampp

Got you. Okay. That's it from me. Thanks for the help, guys.

Thomas C. Stabley

Yes.

Operator

[Operator Instructions] Our next question comes from Kim Pacanovsky with Imperial Capital. Your line is open.

Kim Pacanovsky

Yes. Hey, good morning, everybody. Could you talk about your NGL pricing assumptions in your IRR curves and how those compare with current unhedged realizations?

Thomas C. Stabley

Yes. Kim, its Tom. So the assumptions that we make in our C3+ NGLs is 50% of the WTI pricing, so if you look at where WTI is on our $3 NYMEX and $60 WTI, you'd be talking about approximately $30 for our C3+ basket. And that’s probably a little bit above where current pricing is, but I think with our hedging, it’s probably put you right about where we are.

So $30, $60 WTI are roughly $30 C3+ mix for Rex given where we are and the pricing we receive is again probably a little bit above where the current market is, although proppant has had a really nice run here the last week to 10 days or so along with C5s. But on a hedged basis it’s probably very close to where we are.

Kim Pacanovsky

Okay. Great. And have you considered converting any of your three ways to just realize a fixed bottom on pricing?

Thomas C. Stabley

Yes. So we did some of that early on with our crude, with our crude three ways. On the gas side we continue to look at those on a regular basis and have done some conversions, but depending on the valuation of those conversions, its something we're continuing to monitor.

Kim Pacanovsky

Okay. And last question. What kind of timeframe of production or number of well data will your engineers – your outside engineer need to actually book at the higher number of 15 Bcf target?

Patrick McKinney

Hey, Kim. This is Pat. You typically need to get six months or so production history to really go and validate the curves. So, I don’t know if we'll be there by our mid year reserve process, but we feel very comfortable by year end, year end 2015 that we'll be there.

Kim Pacanovsky

Great. Thanks a lot, guys.

Thomas C. Stabley

Thanks, Kim.

Operator

Our next question comes from Marshall Carver with Heikkinen Energy Advisors. Your line is open.

Marshall Carver

Yes, on Moraine East with the partner or the JV plans there, are you looking more for upfront capital or more of a drilling promote? And if the JV comes in the form of a drilling promote, would that decrease your capital budget or would you more likely drill and complete more wells there this year?

Thomas C. Stabley

Yes. Hey, Mark. So it’s Tom. As we mentioned earlier, we're looking at both financial and strategic partners that can include a drilling type partnership is you are commenting on or can include more of a traditional cash and carry type structure.

So, we're discussing and having conversations with both types of groups. I think if we went with more of a financial type structure with a drilling type carry, my guess is, given the current market conditions and plans to preserve capital, that we would probably lower our capital budget further and again, continue to preserve capita. But probably still maintain strong double-digit growth from what we had originally guided to.

Marshall Carver

Okay. Thank you. My other questions were answered. So thank you very much.

Operator

Thank you. That concludes the Q&A session. I will now turn the call back over to Tom Stabley for closing remarks.

Thomas C. Stabley

Great. Well, thank you all for participating in our fourth quarter year end conference call with Rex Energy and we look forward to speaking with you all in first quarter. Thank you.

Operator

Thank you. Ladies and gentlemen.