Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)  

Rex Energy (NASDAQ:REXX)

Q2 2014 Earnings Call

August 06, 2014 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

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

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

Jeffrey Grampp - Northland Capital Markets, Research Division

Operator

Good day, ladies and gentlemen, and welcome to the Rex Energy Corporation conference call to discuss the company's second quarter 2014 financial and operational results. [Operator Instructions] This conference is being recorded.

I would now like to introduce Mr. Mark Aydin, Manager, Investor Relations. Please go ahead, sir.

Mark Aydin

Good morning, and thank you for joining us for the second -- for the Rex Energy Second Quarter 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, Michael Hodges.

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 2013 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 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 second quarter 2014 results. The second quarter was another solid quarter for Rex Energy, both financially and operationally. Slide 3 shows some of our more recent highlights and achievements from the second quarter, which Michael and Patrick will take you through in more detail later in the call.

This morning I'll be focusing my comments on 2 key themes: the impressive potential for value creation we see in our Butler Operated Area and the significant production growth we expect to deliver in the second half of 2014.

Slide 4 shows what we feel are some of the key value drivers in the Butler Operated Area. First, as we announced a couple of weeks ago, we have once again successfully reduced our drilling and completion costs, this time by approximately 7% during the first half of 2014. Our all-in well cost in the Butler Operated Area now stand at $5.5 million for a 4,000-foot lateral with a 150-foot Super Frac completion design. This is down from the year end 2013 number of $5.9 million and down $1 million from our year end 2012 number of $6.5 million. The cost reductions were achieved through a combination of factors, including reduced drilling days, lower service costs by leveraging our growing scale and improved efficiencies in our operations. Even though we have reduced capital cost by 7% in the first 6 months of 2014, we still believe there are opportunities for additional cost reductions in 2014 and beyond. One of the main factors that we believe will lead to additional cost efficiencies in our transition towards greater pad density, simply increasing the average number of wells on a pad by as few as one can reduce our all-in drilling cost by $50,000 to $100,000 per well. As expected, the reduction in well cost also drives rates up of return. In the Butler Operated Area, our rate of return for a typical Butler Operated Marcellus well increased approximately 10% during the first half of 2014, with a significant portion of this increase being attributed to the lower well cost.

Operationally, we continue to build a more contiguous acreage position in the Butler Operated Area, adding approximately 2,200 net acres to our core area during the first half of 2014. These acreage acquisitions are important to Rex, allowing us to increase lateral lengths and pad density. A good example of this is the 3-well Shipley pad, where we were able to drill 3 wells with an average lateral length of approximately 7,000 feet, the longest average lateral length in the Butler Operated Area today. In addition, the additional acreage adds to our already robust inventory of over 900 liquids-rich drilling locations in the Butler Operated Area.

On the midstream side, we continue to work with our midstream partners to secure the necessary processing capacity and firm transport that Rex needs to continue to create value and grow. In the Butler Operated Area, the Bluestone II processing facility was recently commissioned and has increased our total processing capacity in the Butler Operated Area to approximately 190 million cubic feet per day, allowing us to continue our development plan and facilitate our growth. We are currently in negotiations with our midstream provider for expansion to Bluestone II facilities -- to the Bluestone facilities to substantially increase our processing capacity in the Butler Operated Area and set the stage for future growth in 2015 and '16. You can see from the comments that our Butler Operated Area continues to deliver increasing value to Rex, and we believe we are still in the early stages of demonstrating the full value of this asset.

Another important point I would like to highlight this morning is the substantial production growth we expected Rex to deliver in the second half of 2014. As we have previously announced, our production guidance for the third quarter of 2014 is approximately 159 to 165 million cubic feet equivalent per day, which represents 26% growth at the midpoint of our guidance. This growth, combined with what we believe will also be robust growth in the fourth quarter, demonstrates the quality and the potential of our assets in this portfolio. In addition, due to the strong performance of our assets, as well as the operational execution we have seen so far this year, we recently increased our full year production guidance to 146 million cubic feet to 150 million cubic feet equivalent per day, compared to our previous guidance of 143 million cubic feet to 149 million cubic feet equivalent per day.

There are several important catalysts to the anticipated growth in the third quarter of 2014. In the Warrior North Prospect, we will be placing the 6-well Grunder pad into sales during the third quarter. The Grunder pad is significant for a number of reasons, not the least of which is that it is located in the western portion of our Warrior North Prospect, which we believe is prospective for higher liquids production as compared to the eastern portion of our acreage. We also tested 600-foot and 500-foot downspacing on these wells, and we expect the results of these wells to provide us with valuable data points regarding the potential to successfully add location to our existing inventory, which is currently based on 750-foot spacing between laterals. In the Butler Operated Area, we anticipate placing at least 8 wells into sales in the third quarter of 2014 to drive our substantial production growth in that area. The 5-well Ferree pad, which we currently expect to be placed into sales in the third quarter, is another important data point for Rex. Not only because the 5 wells in the pad have an average lateral length of 5,500 feet, but also because the pad is our second test of vertically stacked Upper Devonian Burkett and Marcellus laterals. We anticipate that the Ferree pad, along with other previously completed Baillie Trust pad, will further demonstrate that the Upper Devonian and the Marcellus are 2 separate producing reservoirs. We are also placing into sales the 2-well Dorsch pad, which we drilled to an average lateral length of approximately 4,700 feet, in addition, tested 500-foot spacing.

I'll conclude with some brief comments about ethane. We began selling ethane during the second quarter, ramping up our volumes over time as Bluestone II processing facility was commissioned. We have discussed ethane sales a good deal in the past. The key fact now is that with the new plant fully operational, we are able to receive value for our ethane. We were previously burning a significant portion of our ethane as plant compressor fuel. So while ethane prices are not currently favorable, ethane still -- ethane sales still deliver incremental value to Rex. We are currently selling approximately 5,000 barrels per day of ethane and anticipate these ethane volumes will remain consistent throughout the remainder of the year, contributing to our growth in the second half of the year.

I would like to now turn the call over to our Chief Financial Officer, Michael Hodges.

Michael L. Hodges

Thanks, Tom. On Slide 5, we have a summary of our operational and financial highlights for the second quarter of 2014. While I will not repeat results from the release last night or the slide shown, I would like to point out that our EBITDAX from continuing operations for the first half of the year is up almost 60% over the first half of 2013, which is tremendous growth in a very short time period. In addition, our cash cost per unit comprised of LOE and G&A per unit decreased by 3% over the first quarter of 2014, and our year-to-date cash costs are down 5% compared to the first half of 2013.

Moving to Slide 6, I'd like to spend some time this morning discussing the impact of Northeastern basis differentials on our second quarter results, as well as discuss our view of the impact of these differentials going forward. This issue has certainty garnered significant attention recently, and I would like to spend a few moments this morning addressing some of those recent concerns.

First, to recap, our unhedged price realization for the second quarter for natural gas was $3.96 per Mcf or $0.71 below the average NYMEX settlement price for the quarter. However, as you can see on Slide 6, when you include the impact of our basis differential hedges, our realized natural gas price was $4.05 per Mcf or $0.62 per Mcf below the average NYMEX settlement price. I would also point out that halfway into 2014, our price realization for natural gas has been only $0.16 below the Henry Hub price. And given that the fourth quarter of 2014 may likely include tighter differentials due to the seasonality of the Northeastern basis markets, I would assert that Rex's 2014 natural gas price realizations may be much better than current market sentiment might indicate.

Looking ahead, we continue to monitor the Northeastern gas markets for changes in future basis differentials. As you are likely aware, current basis differentials for the market such as Dominion South Point or TETCO M2 and M3, where Rex sells a majority of its gas, have widened considerably from their historical levels. That said, I would point out a number of factors which we believe may be getting overlooked as part of the recent intense focus on natural gas basis differentials. First, Rex's liquids-rich production gives a product diversity that some others do not have. While natural gas price realizations are currently challenged, current market prices for propane are over $1 a gallon, up approximately 17% over the same time last year. In addition, our natural gas contains a relatively high BTU content, affording us a 6% to 8% price premium over the index prices typically reported. Next, our basis hedge position for the remainder of 2014 and into 2015 has significant value. At the end of the second quarter, these hedges had mark-to-market value of $3.3 million, which will be realized over the next 9 months at current market values. Finally, I would point out that the seasonality that exists in the basis in the market is real and note that winter basis at Dominion South Point is approximately 40% better than current spot levels. All this said, our forecast for price realizations for basis hedges -- before basis hedges in Q3 and Q4 is that Rex should average approximately $0.20 to $0.30 better than the current basis differential market at Dominion South Point and M2 and M3 due to the high BTU content of our gas. In addition, Rex has approximately 15% of its remaining production for 2014 hedged at $0.37 off the Henry Hub price, a level much tighter than current market values. Using June 30 pricing, this would incrementally add another $0.18 to our natural gas price realizations for Q3.

To summarize, at current market price levels, we would expect our basis differentials for the full year 2014 to be $0.60 to $0.80 below the Henry Hub, including the effects of our basis differential hedges.

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

Patrick M. McKinney

Thanks, Michael. Moving to Slide 7, we recap our proved reserves growth profile. While we issued a press release with this information on July 28, I'd like to take a moment and discuss the highlights as well as some additional information.

Starting with the growth in PV-10, Rex experienced an increase of 56% from year end 2013 to midyear 2014. The increase was driven by a trailing 12-month increase in oil, natural gas liquids and natural gas pricing for about half of that move. But the remaining acreage was driven by continued flattening of our type curve decline rates. We feel that this is the direct result of our "Super Frac" or reduced cluster spacing completion method. This is also reflected in the 24% increase in proved reserves to over 1 Tcfe. A direct result of our reserves' type curve improvement is that Rex continues to drive down its drill-bit finding and development cost. Total company drill-bit F&D in midyear 2014 was $0.74 per Mcfe. This compares to year end 2013 drill-bit F&D of $0.91 per Mcfe. Tom mentioned we continue to reduce our drilling completion cost and specifically, on the drilling operation side, reducing drilling days by roughly 20% from the expectations over the last 10 wells. The 7% reduction in drilling completion cost already experienced by Rex through midyear 2014 are not reflected in the midyear 2014 reserve report. These reductions already experienced, along with the additional target cost reductions anticipated through the end of the year, will be reflected in our year end 2014 proved reserve run.

On Slide 9, we present a summary of our results and testing to date at our Baillie Trust pad. As can be seen on this slide, we have conducted numerous testing procedures and have closely monitored the now 8 months of production history to conclude the downspacing and stack and offset positioning of the wells continue to affirm the company's belief that the Marcellus and the Upper Devonian Burkett formations can be developed as separate reservoirs. This pad is significant for Rex as it is our first true test towards optimal full field development, demonstrating the concept of downspace and stacked and offset development of our Marcellus and Upper Devonian Burkett intervals. Our current nonproved resource inventory and proved reserve inventory are set on 750-foot lateral spacing. Proving the downspacing towards the 600- to 650-foot level should add approximately 20% to our nonproved and proved well inventories. As Tom also mentioned, this optimal full field development will have much higher well density per pad and will continue to drive drilling completion costs lower. Moreover, with the continued production history profile we report on our Upper Devonian Burkett wells, we continue to feel encouraged that this interval will be on par with our Marcellus reserve and production profile. We'll continue to validate this thesis at our Ferree pad, where we have 4 Marcellus wells below one Upper Devonian Burkett well stacked and offset directly above. We also have our 6-well Michael pad that will be completed in early 2015 that has 3 Marcellus wells and 3 Upper Devonian Burkett wells stacked and offset at 650-foot spacing.

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 Leo Mariani from RBC.

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

I just wanted to follow-up with you on the Baillie Trust pad. You guys obviously seem confident you can develop these as separate intervals here in the Upper Devonian and the Marcellus. Are you seeing any communication at all between those reservoirs at this point in time?

Patrick M. McKinney

Leo, this is Pat. After 8 months of production history and various interference testing, bottom hole pressure buildup, transient analysis testing, we have seen no direct indication of any interference between those intervals.

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

Okay. That's good to hear for sure. Maybe just jumping over to Butler. Obviously, you guys talked about the potential for reducing well cost going forward by adding kind of one well to each pad. Are there any other things that you guys can see that could drive well costs lower and efficiencies better over the next couple of years?

Patrick M. McKinney

Yes, Leo, this is Pat again. I mean, I think one of the things, as Tom mentioned, you're going to see the reduction just by increasing the well density. But along with that, when you start looking at higher density pads, you get additional scale on service costs, on efficiencies and logistics, that I think will be borne out, and increasing velocities. So the number we throw out of $50,000 to $100,000 is kind of just our fixed cost loading of all the costs per title and to prepare the pad and build the pad and the leased road. But I think you're going to gain additional efficiencies and scale when you look at these larger pads on logistics, service costs, and then just velocity on these pads.

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

Okay. That's good to hear for sure. Any update on Illinois in terms of what your plans are for that asset?

Thomas C. Stabley

Yes, I think our plans on the Illinois asset remain the same. We're continuing to do some additional testing this year on vertical step out wells. We're continuing to look at the productivity at the refracs and put together an inventory that we can establish in that basin to put it back on a growth trajectory that's commensurate with the rest of our portfolio. So I think, as we said in the past, as we get to the end of this year we'll have an update for the market on what we think that inventory looks like and what we think we can get that basin to grow at on a year-over-year basis going forward. So that's probably something we'll have as we get towards the end of the third quarter, probably early fourth quarter.

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

Okay. And I guess, just final question in terms of gas price realization. I just want to clarify that I heard you guys correctly. Michael did you say that you guys are expecting to be $0.20 to $0.30 above kind of Dominion South, TETCO M2, M3, here in the third quarter, is that correct?

Michael L. Hodges

Leo, that's exactly right. Our BTU content in the gas gives us that 6% to 8% uplift. So depending on what you assume the sales price of the gas is in the quarter, that's typically $0.20 to $0.30 above the index price that you might be looking at.

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

Okay, got you. And I guess maybe just a quick follow-up on that. Any indication of whether or not you all may be able to access some different markets? Any kind of progress on new midstream deals for Rex? And maybe just kind of talk about how that may unfold over the next couple of years.

Thomas C. Stabley

Well, I think, Leo, it's Tom. I think we are very proactive in our ability to get into the Texas Gas system and get to the Gulf Coast. That 130 million really should cover us depending on the percentage of capacity that we want to be hedged at. I think we're thinking somewhere in the 60% to 70% range is what we want to be firmed out at. I think that will get us through kind of Bluestone III, maybe into early Bluestone IV. And so we're starting to look at our options beyond that. There certainly are a large number of projects that are coming into the area. And I think for Rex it will be important to continue to look at those other projects to get us out of the basin. So I don't have anything to talk about today on the call specifically. But certainly, Rex is continuing to look at opportunities to get out of the basin. But more importantly, as others get out of the basin, that should help to improve the overall differentials in the actual Appalachian Basin. So I think it's not just us getting out of the basin, it helps us in the Appalachian differentials. I think it's all of the other gas that others are also working to get out of the basin. So I think, for us, it's a two-pronged approach. Work to get our gas out and then get the benefit of others moving their gas out of the basin.

Operator

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

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

Say, a couple of questions. First, maybe just a quick one for Michael. Michael, just wondering, I think it's this quarter I think -- I'm sorry, I think it was actually last quarter, where the ethane is now starting to run through that Enterprise ATEX, and the NOVA Mariner West pipeline. I'm just wondering what type of prices you're seeing today for that. And how that would compare versus if you were still having to reject. I realize, I mean, you've certainly said in your prepared remarks. I know prices aren't that good today, and they're likely going to be increasing. But I think you're still certainly getting a bit of an uplift there versus the prior, isn't that correct?

Michael L. Hodges

Yes, yes, Neal. I'll walk you through that a little bit. So the ethane that we sell through the Mariner West system is priced on a gas basis. So it's really, in that sense, it wouldn't be any different if you were rejecting it versus selling it. I think I would caveat that by saying we really haven't gotten value for our ethane in the past because it was used as fuel in our compressors. So -- whereas other guys would be indifferent to blending versus selling the ethane at those prices, we actually do receive incremental value. So we have a portion that goes onto the Mariner West system. The other portion goes on to the ATEX system. We do receive Mont Bellevue ethane pricing for that. We've talked in the past about it costing us about $0.20 to $0.22 to get down to the Gulf in order to get that pricing. So it's a 2 stream for us between Mariner West and ATEX. And like I said, it's really an incremental uplift over where we were in the past.

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

Okay, good point. Secondly, maybe just for Tom or Pat, on just looking at where you're north and south in the Utica. Your thoughts on -- seems like these wells, as you mentioned, are definitely holding on. It appeared to me that they're still running, is it fair to say a bit above the type curves, I guess would be my kind of first question, Pat, for you and Tom. How those are kind of looking versus the type curves? And then secondly, beyond that 6-well J. Hall pad in the south and 3-well Jenkins in the north, just I guess -- I know I don't want to look too much into '15 yet, but do you anticipate a program about as active next year as you have been this year? I mean, you certainly have been quite active.

Patrick M. McKinney

Yes, Neal, this is Pat. I'll comment on the well performance. I think from when we put out kind of range of type curves and the commentary on the condensate yields and where they're stabilizing, yes, from our last update when we looked at type curves and EURs, we feel the wells are still performing along those lines. So -- but we'll, at the end of the year, we'll kind of revise that and kind of put out where we think the condensate yields are going to be. But as we sit here today, those wells are still performing to our expectations.

Thomas C. Stabley

Yes, I mean, Neal, it's Tom. As far as the activity level for next year, I think you've heard Pat talk about the acceleration in the number of drilling days. We've been able to see some of that same savings in the Ohio side. I think that should allow us, just by continuing to run that one rig next year, along with some of the increased pad density, and we're north as well, allow us to get an increased number of wells. So I think we've got a total of about 15 this year, should allow us to push that number closer to maybe 20 just with operating that one rig with the improvements we're seeing and the velocity. So I wouldn't expect a whole lot more than that as we go into next year.

Operator

Our next question comes from the line of Jeff Grampp from Northland Capital.

Jeffrey Grampp - Northland Capital Markets, Research Division

Just kind of a high-level strategic question on the liquidity front. Obviously, you guys are in a great position with the notes offering. Just kind of wanted to get your thoughts on rig counts moving forward, maybe in Butler. I know you just kind of touched on Utica. And maybe how you guys plan to incorporate any macro views on the nat gas front in that decision?

Michael L. Hodges

Yes, Jeff, this is Michael, and Tom can certainly jump in. But I -- we certainly haven't released anything official for next year. But I think we're pretty comfortable with where we're at with our core asset there in Butler. We're running the 2 rigs. I don't know that we have any plans in the short run to change that over in Ohio. As Tom just mentioned, we run the one rig toggling between the north and the south. Again, I don't see anything that changes that. I think you talk about the macro issues. I think, for us, a large portion, as we've talked about, of our production is liquids-based. And so to the extent that those prices have actually strengthened over the last, call it, 12 months, I don't know that our macro view of activity has really changed. So we'll continue to monitor the situation and certainly update if we need to. But I think our current outlook is, is that it's a similar level of activity in '15 as we have in '14.

Thomas C. Stabley

Yes, I think the only thing to add to that, Jeff, is -- again, as Michael said, when you look at the value of the liquids -- and roughly 40% of every dollar that we sell in Butler is really on the liquids side, the value really does get driven from those wells or a big portion of the value can be driven off the liquids. The improvement in the well cost, I mean, I think it continues to be missed. We're down to the $5.5 million. And what that has meant, even with some of the increase in basis differentials, we're still up 10% on an IRR basis year-over-year. So in light of some of the issues we've seen around the basis, the improvement that we've had on the well cost, the improvements on the liquids side, our continued reduction of the LOEs on a per unit basis with some of the water management we've done, I think continues to point to the improvements we've had in the -- over our IRRs. As far as growth goes in Butler next year and how those types of thing impact our decisions, I think when we're able to talk about kind of the next expansion in Bluestone and what that means for Rex, you'll get a lot better indication of kind of how Rex is going to grow through 2015 and 2016. But again, with the quality of the asset we have here, the liquids component that we have, the productivity that our midstream partners are bringing us on the processing side, you'll get a lot stronger indication of that when we put out our budget going forward into '15 and '16.

Jeffrey Grampp - Northland Capital Markets, Research Division

Okay, got it, yes, great point. And then I just kind of wanted to get maybe some incremental color on how you guys look at EUR and cost increases as you guys extend those lateral lengths out. Just kind of give us a sense for how we should be thinking about, maybe on a percentage basis, with EUR gains and the relative cost increases as you guys push these laterals out longer?

Patrick M. McKinney

Jeff, this is Pat. Obviously, we updated our IRRs again for the 4,000-foot lateral Butler recently with some of the cost reductions that we got, as well as kind of flattening out of the decline curve. We're going to go through and do our typical process where we're going to gather all that information, look at as much production history as we can. When we get to year end, we typically go in and look at if you want to take our type curve lateral length and EUR out to reflect what we're drilling. So to be sure, as Tom mentioned, we're going for longer laterals. So we need to go and take all that production history and go and look at what the type curve is going to look like at 5,000 feet, as an example. And we typically do that at one pass as we get to year end for year-end reserves.

Jeffrey Grampp - Northland Capital Markets, Research Division

Okay, got it. And then last one for me, just on the downspacing. How do you guys see timing playing out there where you guys may feel comfortable revising the location count given the downspacing results you guys have had. Is that kind of a year-end event, too, similar to the lateral length?

Thomas C. Stabley

Yes, I think we've been pretty consistent. As we get to the end of this year, and we have all of the data from the Baillie Trust, the Shipleys, the Ferrees and some others, we'll be in a position to get you an update on that well count. I mean, again, as we sit here today on the Shipley and the Baillie Trust, we've not seen that. We'll get some important data out of the Dorsch pad that's going to take us down to actually 500 feet. We'll be able to see how that one flows. So I think we'll have enough information when we get to the end of the year to be able to update those, along with some additional color on the additional acreage we have leased this year and what that could mean to the overall well count. And then lastly, what that means on an average lateral length for next year, and then probably even into '16 of what we expect to drill. So a lot of information as we go into the end of the year with that being another catalyst for Rex, certainly.

Operator

And that concludes our question-and-answer session for today. I would like to turn the conference back to Tom Stabley for any closing comment.

Thomas C. Stabley

Great. Well we appreciate everybody participating on Rex's second quarter call, and we'll look forward to seeing you on the third quarter call. Thank you.

Operator

Thank you. 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.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Rex Energy's (REXX) CEO Thomas Stabley on Q2 2014 Results - Earnings Call Transcript
This Transcript
All Transcripts