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

Rex Energy (NASDAQ:REXX)

Q4 2012 Earnings Call

February 27, 2013 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

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

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

Gordon Douthat - Wells Fargo Securities, LLC, Research Division

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

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

Jeffrey P. Hayden - KLR Group Holdings, LLC, Research Division

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

Operator

Good morning, ladies and gentlemen, and welcome to Rex Energy Corporation's conference call to visit -- to discuss the company's fourth quarter and full year 2012 financial and operational results. [Operator Instructions]

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

Mark Aydin

Good morning, and thank you for joining us for the Rex Energy Fourth Quarter and Full Year 2012 Financial and Operational Update Call. On the call today is our Chief Executive Officer, Tom Stabley; our President and Chief Operating Officer, Patrick McKinney; and our Chief Financial Officer, Michael Hodges. We hope you've had time to review yesterday's 2012 fourth quarter and full year financial and operational release.

Today's discussion will include forward-looking information and reference non-GAAP financial measures. Please review our cautionary statements in the release and the accompanying slide presentation. In addition, you should refer to the disclosures in our 2011 Form 10-K and other SEC filings regarding factors that could cause our future results to differ from this forward-looking information.

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

I would like to now turn the call over to our Chief Executive Officer, Tom Stabley.

Thomas C. Stabley

Thank you, and good morning. Before we begin, I'd like to take a moment to express our condolences regarding the incident at our Brace West pad in Ohio on Monday, where one of our drilling contractor's employees was fatally injured. We are deeply saddened by the event, and our thoughts and prayers have been with the young man's family and co-workers. Rex is continuing to support the drilling contractor and all relevant authorities as their investigation of the accident proceed. The site has been temporary shutdown and will remain so until the authorities give us word that we can resume our operations. Thank you.

Starting with Slide 4. We have provided a summary of our operational and financial highlights for the fourth quarter. Production came in at 73.9 million cubic feet equivalent per day, which represents growth of 50% over the comparable quarter last year, including 43% growth in liquids. Due to that growth, we were able to achieve our exit rate goal of 30% liquids mix. Total liquids production for the company averaged over 3,500 BOEs per day for the fourth quarter. Our growth in liquids production is a result of continued drilling successes in our liquids-rich portions of the Butler Operated Area, solid results from our liquids-focused Ohio Utica program and incremental oil production from our Illinois Basin conventional drilling and refrac program. In our Butler Operated Area, Patrick is going to speak to the results of our recent Marcellus wells, which are some of our stronger for the company. I will focus my comments this morning on our most recent Upper Devonian Burkett well, as it, too, in early production, is one of the top wells for the company in our Butler Operated Area.

The Drushel 6-HD, our second producing Upper Devonian Burkett well, was recently completed and flowed into sales with a 5-day sales rate of 7.3 million cubic feet equivalent per day, assuming full ethane recovery. The well was drilled in the fourth quarter of 2012 and completed during the first quarter of 2013 using a 150-foot frac stage design. The well produced approximately 3.7 million cubic feet per day of gas, 598 barrels of liquids per day during its first 5 days into sales. These results place the Drushel 6-HD in the top 5 in terms of initial 5-day results from our Butler Operated Area today, and this is from only our second well completed in the Upper Devonian Burkett. With nearly 50% of the production from the well coming from liquids and our strong price realizations, which is approximately 50% of NYMEX for the company's C plus -- C3 plus stream during January, we believe the economics of the Drushel 6-HD are very strong. In addition, even though the well reported only 12 barrels of condensate per day in the first 5-day sales period test, we have seen this rate come up closer to 25 barrels of condensate per day in recent days. These are encouraging results.

During the remainder of 2013, we plan to drill one and complete 3 additional Upper Devonian Burkett wells in different areas of our acreage. As a reminder, 2 of the 3 wells we plan to complete this year lie to the northwest of our projected 1,300 BTU line in the Marcellus, and we are expecting these 2 Burkett wells to also be at or above the 1,300-BTU level. Our current plans for 2013 will bring our total number of Upper Devonian Burkett wells into sales by 5 by the end of this year. We believe these 5 wells will further delineate the liquids-rich portion of our acreage and show the true value and resource potential of our second producing zone in our Butler Operated Area.

Staying in the Butler Operated Area, we also announced last night that we entered into an ethane sales agreement with NOVA Chemicals Corporation to sell ethane produced in Butler Operated Area via the Mariner West pipeline project. The agreement calls for initial volumes of 2,000 barrels per day of ethane, and pending an exercise of an option by NOVA, could increase over the term of the agreement. First sales under this agreement are scheduled to begin in conjunction with the company's Y-grade liquids line from Butler to the MarkWest Houston facility in Q1 of 2014. This agreement with NOVA, along with the company's ATEX agreement, provides Rex with 2 outlets for ethane sales and initial takeaway capacity in 2014 of approximately 5,000 barrels per day out of Butler Operated Area. We will continue to explore other markets as the company's ethane sales continue to grow.

Lastly, in the Illinois Basin, we are pleased to announce that we surpassed our initial goal of adding 400 gross barrels of oil per day in the fourth quarter through our conventional drilling and recompletion program. During the second half of 2012, we drilled 8 new wells and recompleted 15 wells at a gross cost of approximately $11 million. During the 6-month period, the highest 1-day peak rate for the production from this program was 849 gross barrels of oil per day, which we believe is a strong indication of the potential of this program. We currently plan to spend approximately 18 million on the program in 2013, which will fund the drilling of 19 and recompletion of 9 additional wells in different locations and zones within our acreage throughout the basin. To date, our program has tested our acreage vertically, but we have currently begun to drill our first horizontal well to further test the potential of the acreage. The program laid out for 2013 should allow the company to further delineate the total resource potential of its current acreage position in the Illinois Basin.

In conclusion, I'm pleased to announce that Rex Energy has exceeded 100,000 net acres in the Appalachian basin, a significant milestone in the company's history. We now have over 48,000 net acres in our Butler Operated Area, 20,000 net acres in the Warrior prospects, and of these 100,000 acres, we believe approximately 75% to be liquids-rich, and 50% of the acreage is prospective for multiple horizons.

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

Michael L. Hodges

Thanks, Tom. Moving to Slide 5, I'd like review some of the operational and financial highlights for the quarter. As Tom mentioned earlier, our average daily production increased 4% over the third quarter of 2012 and 50% over the fourth quarter of 2011. Oil and NGL production for the quarter increased 18% over the third quarter, or by over 500 barrels per day, and accounted for 29% of our total production for the quarter. We believe this trend of increasing liquids production will continue into the future as we continue to allocate the majority of our capital to developing our liquids-rich assets.

Lease operating expenses for the quarter were $13.1 million, or approximately $1.93 per Mcfe. The $1.93 per Mcfe number is a 4% decrease on a per-unit basis as compared to the fourth quarter of 2011. Strong production from our Marcellus wells and lower operating costs for the existing wells contributed to the improvement on a per-unit basis over the fourth quarter of 2011. As we continue to develop our Appalachian Basin assets, we believe lease operating expenses will continue the downward trend on a per-unit basis.

Adjusted net income, a non-GAAP measure, for the fourth quarter was approximately $6.0 million or $0.11 per share. Loss from continuing operations attributable to Rex common shareholders for the current quarter was $1.3 million, or a loss of $0.03 per share. EBITDAX for the continuing operations, a non-GAAP measure, was approximately $26.4 million for the fourth quarter or $0.50 per share, which is a 33% increase over the fourth quarter of 2011 and a 16% increase over the third quarter of 2012. The increase over the prior quarter was due to the increased production during the quarter and higher realized prices on both our national gas and on our natural gas liquids.

For 2012, our average daily production increased 72% over 2011. Oil and NGL production for the year increased 23% over 2011 or by approximately 550 barrels per day and accounted for 27% of our total production. LOE for the year was $47.6 million, or approximately $1.94 per Mcfe. The $1.94 per Mcfe is a 17% decrease on a per-unit basis as compared to 2011.

Adjusted net income, a non-GAAP measure, for 2012 was approximately $16.7 million or 32% -- $0.32 per share. Loss from continuing operations for 2012 was $56.4 million or $1.09 per share. EBITDAX from continuing operations, a non-GAAP measure, was approximately $87.7 million for 2012 or $1.64 per share, which is a 40% increase over 2011. For a detailed reconciliation of these non-GAAP measures to GAAP net income, please see the appendix at the end of our presentation.

Moving to Slide 6, we present a summary of our price realizations for the fourth quarter. Prior to the effects of hedging, realized prices for the quarter were $85.33 per barrel of oil and condensate, $3.54 per Mcf for natural gas and $48.27 per barrel of natural gas liquids. Cash settlements from gas hedges increased our realized price by $0.56 per Mcf for the quarter, resulting in a net price of $4.10 per Mcf. Realized prices for NGLs were also positively impacted by hedging activities during the quarter, increasing our realized price by $1.33 per barrel to $49.60 per barrel.

On Slide 7, we get a summary of our current hedge position for 2013 oil and natural gas and natural gas liquids production, which will provide predictable cash flows as we execute our capital program. We have over 85% of our 2013 oil production hedged and over 90% of our natural gas production hedged, at what we believe are very attractive levels. Of particular note is our natural gas hedge position for 2013, where we are hedged at an average floor price of $4.30 or approximately 20% above the 2013 gas strip price. Additionally, we have approximately 50% of our total NGL volumes hedged at very strong prices. We are continuing to layer on hedges for oil, gas and NGLs in 2014 as opportunities present themselves.

Moving to Slide 8, I would like to discuss our first quarter 2013 guidance. We expect first quarter average daily production to be between 71.5 million and 73.5 million cubic feet equivalent per day. While this represents a slight quarter-over-quarter decline at the midpoint of the guidance range, it is important to point out that this is simply due to the timing of the wells being placed in service. For the first quarter, we currently expect only 4 wells to be placed in service and have a meaningful impact on our fourth -- first quarter production. However, in the second quarter, we expect approximately 13 wells from both our Butler Operated and Ohio Utica areas to contribute to significant sequential production growth. First quarter LOE is expected to be in the range of $13.0 million to $14.5 million, and cash G&A expenses for the first quarter are expected to be in a range of $5.8 million to $6.8 million.

For the full year of 2013, we are maintaining our guidance range of 90.5 million to 94.5 million cubic feet equivalent per day for production, $58 million to $62 million for LOE and $26 million to $29 million for cash G&A.

Lastly, I'd like to spend a moment to discuss Rex's strong liquidity position. In the fourth quarter of 2012, we completed our offering of $250 million of senior notes. We received proceeds are approximately $243 million, and used the proceeds to repay all of the borrowings under our revolving credit facility and to repay our second lien term loan. We now have a $240 million borrowing base on our revolving credit facility, which is completely undrawn. The borrowing base is currently undergoing its year-end redetermination, and we should have update to provide toward the end of March or the beginning of April. With our completely undrawn borrowing base and cash on hand, we entered 2013 with approximately $284 million of liquidity, which fully funds our capital expenditure program for 2013 and takes us well into 2014.

With that, I would like to turn the call over to our President and Chief Operating Officer, Patrick McKinney.

Patrick M. McKinney

Thanks, Michael. Slide 9 summarizes our 2012 year-end proved reserves. Proved reserves increased 69% over 2011, driven by increasing EURs in our Butler Marcellus program and the ability to book ethane recoveries starting in 2014. Without the ethane booking, proved reserves still had very healthy growth from 366.2 Bcfe to 495.6 Bcfe, or 36%. The current liquids content of our proved reserve base stand at 41 million barrels or 40% of the total. At year-end 2012, Rex's product breakdown was approximately 9.4 million barrels of oil and condensate reserves, 32 million barrels of natural gas liquids reserves consisting of 11.4 million barrels of C3 plus and 20.3 million barrels of ethane. We had a PUD-to-proved-developed booking ratio of 1.08:1 net wells in the Appalachian basin, and 42% of our 2012 reserves are in the proved developed category. We successfully replaced 802% of our 2011 production with a reserves-to-production ratio of 25.2 years. Since 2010, we have roughly tripled our proved reserves to 618 Bcfe, and our PV-10 has also increased significantly over the same time period, even in the face of lower natural gas pricing.

On Slide 10, we have a summary of our finding and development costs. As you can see, we significantly lowered both our drill-bit and all-in finding and development costs. Drill-bit F&D costs for 2012 were $0.90 per Mcfe, and we had a 3-year average of $0.96. All-in F&D costs were $0.95 per Mcfe, and we also had an all-in 3-year average of $1.43. As a note from the total company F&D, the drill-bit F&D from our Appalachian unconventional program was $0.73 per Mcfe in 2011. All these numbers put Rex in the top tier of low-cost drillers in our space.

Turning to Slide 11, and following up on Tom's comments on our successful Upper Devonian Burkett test, we are very pleased with the early results from the company recently completed Marcellus well, the Meyer 2H. The 2H was completed using the "Super Frac" design with a 27-stage simulation on a 4,028-foot lateral and was placed into sales in February. It produced at an average 5-day rate of 6.9 million cubic feet equivalent per day and 49% liquids, assuming full ethane recovery. With the continued strong results seen by our recent -- recently completed "Super Frac" wells, we plan to continue this completion method on all wells for the remainder of 2013.

The company's planning to complete 4 more wells above its projected 1,300 BTU or Super Rich line in 2013. 2 of these completions are Marcellus wells, the Wack 9H and the Grubbs 2H, which we plan to place into sales during the second quarter of '13. Recall that we previously noted that these wells at and above this 1,300 BTU line exit exhibited C3 plus liquids yields of 56% higher as compared to the company's average Butler Operated Marcellus production.

One last note on these Super Rich wells. We estimate that they may contain up to or over 50% liquids. This would mean that each of the wells would have close to 650,000 barrels of natural gas liquids reserves, which would significantly improve the already attractive economics of this part of the play.

Slide 12 is a summary of our "Super Frac" Marcellus completion characteristics. While this slide is a bit busy, what we're attempting to show is our progression on our "Super Frac" tests, taking into account stage spacing of 225 feet versus 150, lateral length separation of 950 feet down to 650 feet and the varying effects of both restricted choke flowback and extended shut-in periods. Comparing our shut-in wells against the Plesniak 3H, which did not have an extended shut-in, the results indicate that the combination of extended shut-in and restricted choke yield a 25% to 35% increase in early time flow and pressure profiles of these wells. We feel the extended shut-in allows time for the frac water to dissipate off the formation and the restricted choke allows for less drawdown on the shale phase. We still need another 6 to 9 months of production history to determine the optimal stage spacing and lateral length separation, but we're really encouraged by what we're seeing today.

Moving to our Warrior North Utica program on Slide 13. Recall in September 2012 we placed into sales our first Utica well, the Brace 1H. The most recent results from the well are an average 60-day sales rate of 597 BOE per day and average 90-day rate of 515 BOE. We continue to be encouraged by the results of the Brace 1H. As Tom mentioned earlier, we have completed the drilling of 2 wells on the G. Graham pad and are currently fracture stimulating these wells. The wells will be shut-in for 60 days following completion and placed into sales in the second quarter of '13. For the full year 2013, we plan to drill 7 wells in the Warrior North area and complete 5, placing into service 4 wells.

Moving to Slide 14 and our Warrior South prospect area. We've drilled and completed all 3 plant wells in 2012. The wells have been shut in since completion, and we plan to place them into sales in June once the necessary infrastructure is in place. The rig will then move south and drill and complete 4 to 5 additional wells in 2013 on our next pad, the J. Anderson unit. In total for 2013, we plan to bring on 11 wells in our Ohio Utica play and have a total of 12 wells producing.

I'd like to make one last point concerning drilling costs in our Utica program. We have significantly reduced our drilling costs as compared to the first 5 Utica wells that we drilled in both Pennsylvania and Ohio. In our first 5 wells, we averaged 42 days drilling on location for an average 3,480-foot lateral. Over last 4 wells in Ohio, the company has drilled these wells on average in 23 days on an average of 4,177-foot laterals, a reduction of 19 days, or 46%, notwithstanding the longer lateral lengths. We're pleased with this improvement and feel this will translate into lower drilling costs as we continue our Utica development program.

Slide 15 gives an update on our ASP project in the Illinois Basin. Starting with the Perkins-Smith Pilot Expansion project, we've completed the ASP injection period and plan to start the polymer drying stage of the project in the second quarter of '13. We still expect to see initial production response by midyear '13. Peak production should come at the end of 2013.

In the Delta unit, we've finished drilling and completed all the necessary infrastructure for the project, and pre-flush injection is scheduled to begin in the first quarter of our '13. ASP injection for the Delta Unit is scheduled for the fourth quarter of 2013. Due to the continued positive response from our Middaugh Unit Pilot and the completion of the detailed reservoir simulation modeling and delineation of the Delta Unit, we're able to book net proved reserves of 758 MBO for the Delta Unit at year end '12.

One note of reference regarding our ASP program and its relationship to our conventional test program in the field. Since our ASP program target shallower, water-flooded zones in the Lawrence Field, our conventional test program can be carried out in conjunction with our tertiary recovery efforts. They are not mutually exclusive.

And with that, I'd like to open let's open up the lines for questions and answers.

Question-and-Answer Session

Operator

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

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

Pat, just wondering, going forward now, could you talk a little bit about, both for this and I guess -- or for, I should say, your Marcellus that you just went through in pretty good detail, and then your North and South Warrior. When you start looking at those, is it too early to tell, I mean, as far as downspacing? What's your thoughts kind of on all 3 around like -- Butler, is that able to continue to down space what you're seeing there? And just your thoughts in the Utica play, what's your thoughts on downspacing it?

Patrick M. McKinney

Neal, that's a good question. Obviously, from the slide, you can see that we've experimented on a number of different stage spacing differences from the 225 to the 150, as well as lateral length separation from as far or as close to 1,000 feet, in some of the older wells 500 feet. We're trying to zero in on what that is. So I think we're still going to need about 6 to 9 months' worth of production to really kind of see where that goes. On the Ohio side, we know there's a lot of discussion of downspacing by other operators, but with just one well out there, it's still a bit early for us to make that determination. When we have a couple of these 2-, 3- and 4-well, 5-well pads coming on, I think that will give us a lot of information. So we should see that as we get more production history.

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

Okay. And then, Pat, is it true -- I don't want to hit too detailed, yet, on the Utica. I know you're pretty early there. But I know like Range had mentioned today about, even much further north than where you are, liking the pressure that they're seeing there. So I'm just wondering, when you look at your Northern Warrior versus the Southern, if you can comment yet on kind of different pressures? I mean, does one look that much different than the other? Or are you almost as optimistic -- or as optimistic, I should say, in the North as you are in the South, just based on characteristics you're seeing?

Patrick M. McKinney

Well, we've only got production slowdown on one well in the North, and just like you, I've seen other operators' results. So I think it's a little early for us. But I think it's pretty clear that in the southern end, from the flow test pressures that have been reported, they appear to be a little bit stronger than the North. But again, I think time is going to tell how that's all going to play out.

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

Okay. And then just lastly, going back to Butler, your core there. You continue to squeeze out and do a nice job bringing costs down. I mean, what -- I guess when we look, and I know you've guided kind of for the year, I mean, when you look, how much more can you continue to -- I mean, is it more on the design? Either for Pat or Tom, just wondering, as you sort of, you continue to bring these costs downs, I'm just wondering, is it more of the pad drilling that you're referring to? What is it in these wells, and how much more can these costs come down?

Thomas C. Stabley

Neal, it's Tom. I think as we continue to move forward, the program that we've laid out for this year is still an HBP program. It's our hope that, as we move forward into the future, that a second rig could be brought in at some point. And that rig would be used for pad drilling exclusively, and the first rig will continue on an HBP program. So we're continuing to monitor that. But there certainly is room, once we get into a pad development mode, to bring those costs down another probably 5% to 10%.

Operator

Our next question comes from Ron Mills from Johnson Rice.

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

Can you spend a couple minutes talking about the conventional Illinois Basin? I know the 1-day peak rate was a lot higher than what you guys had expected. But in terms of -- what's the aerial extent of your acreage position that you think is prospective for this, for the conventional activity and some -- what's -- some of the concept behind going horizontal? In other words, is there some sort of analog to some other field in another area that you're trying to test in this Illinois area?

Thomas C. Stabley

Yes. Ron, it's Tom. I'll take the first part and then let Patrick talk about the horizontal piece. We -- Rex currently has about 26,000 acres throughout the Illinois Basin, 12,000 of which is a very contiguous block in our Lawrence Field. The program that we initially started in 2012 focused predominantly on the Indiana side, with some additional drills and, obviously, refracs. We did move over to the Illinois side towards the end of the year and did a couple of tests there. The program that's laid out for '13 really further delineates the remainder of the acreage that we have throughout the Lawrence Field and some other parts of Indiana, not only testing the zones that we looked at in '12, but some additional zones that the geology here at Rex has looked at and feels could potentially be prospective. So we're going to go in and test these vertically. Again, Pat will talk a little bit about the horizontal side, but I think we've got an opportunity here with the acreage we have to get in after some of these bypassed pay zones, some areas that may be in the past were overlooked because the rock was a little bit tighter, and with some of the new frac techniques, get back in and get after it.

Patrick M. McKinney

Ron, this is Pat. The basin is characterized, like a lot of very mature basins, with a number of stack pays, sandstones and carbonates. And as Tom mentioned, that had typically been overlooked in the past because they are -- the porosity is a little bit tighter and you have different stringers of them that lay in the vertical section. So our thought on the horizontal wells is to go in, very similar that's being done in a lot of different areas, go in and lay a horizontal well in and try to go in and catch a lot of that pay that, typically, would not be that productive on a vertical setting. So that's -- it's very similar to the Permian and other stack pays going in, just using modern technology to try go and get out after some of that tighter rock.

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

Okay, great. And in Butler County, of your planned activity this year, I think it's 19 new wells being drilled, what's the well count in terms of the Marcellus versus the Upper Devonian? And/or, if you add a second rig as opposed to just going to development, how -- would you potentially try to accelerate delineation of the Upper Devonian? Or how do you approach that?

Patrick M. McKinney

That's a good question, Ron. I mean currently, we've got about 56 Marcellus producers in Butler. And now, the most recent Upper Devonian is really our second. So if you go back and, from prior presentations, look at our inventory that we've done out there, it's about 50-50 with Marcellus potential locations and Upper Devonian. So getting the 5 additional Upper Devonian wells drilled and completed and seeing some production history on them this year, I think, will put us in a much better position to answer that question. But we feel very good now about the resource potential of our Upper Devonian with this test. So we plan on continuing that effort this year and really hope to be able to get a little bit more color and line of sight of what the development plans are going to be, but we need to have more production on them.

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

Okay, great. And I know you haven't focused much on this. But can you just refresh memory where your acreage up in Mercer and Venango Counties is relative to a lot of the industry-permitted wells targeting the Utica up in portion? I know it's HBP, and you're able to leverage off of industry activity, but what's your position up there? And is it located proximal to the recent industry -- increase in industry permits?

Thomas C. Stabley

Yes. Ron, it's Tom. So our Mercer County acreage is in the northeast corner of Mercer. It's about 6 -- yes, about 6,000 -- 3,000 net acres. We are partnered with Shell in that area. They're the operator of the Utica. We do operate some of it, but for the most part, they operate it. That would be south and east of the well that was announced yesterday by one of our peers, and also in the general vicinity with where some of the other industry wells are being announced. The Warren acreage, which is about 7,000 acres, is probably a little bit north and east of that activity, so probably a little bit of a step out from there. But it is all HBP and sits up there on the very western edge of Warren County. So again, that's HBP. So both areas not something we'll probably look at drilling this year, but just wait to see what the rest of the industry does.

Operator

Our next question comes from Gordon Douthat from Wells Fargo.

Gordon Douthat - Wells Fargo Securities, LLC, Research Division

Just a question for me on NGL pricing and how we should look at that going forward this year. I believe you rejected ethane in the fourth quarter. And I was just wondering, with your guidance, is -- did your guidance for the first quarter and then all of 2013 contemplate ethane rejection? And how might that impact your production volumes, whether or not it did?

Thomas C. Stabley

Yes, so just a note on Rex for ethane sales. As most of you know, ethane for Rex is actually extracted at the plant, and a very small amount is actually put in for ethane rejection. We do not have waivers for our gas sales, so we can only sell into the pipeline at 1,100 BTU. The majority of our ethane is burned as compressor fuel for the engines there in our Butler County plants with MarkWest. So our current ethane rejection is really limited to just 1,100 BTU. So when you look at our sales of ethane, we don't and are not forecasting to have any ethane sales in 2013 other than what we've had through this point. Once we get into the first quarter of 2014, that ethane, along with the remaining C3 plus liquids, will be transported via pipeline down to the MarkWest facilities were it will be fractionated, and we will then have the ability to sell that liquid under our current contracts that were announced last night with NOVA and our previous contracts with ATEX. So as far as '13 goes, back to your original question, the only ethane sales that Rex really has is a very small amount of the ethane being sold under the 1,100 BTU amounts into the Dominion pipeline.

Gordon Douthat - Wells Fargo Securities, LLC, Research Division

Okay, that's good clarity. And then how would that flow through on the pricing side? It looks like you had pretty strong pricing in the fourth quarter. And how should we look at that going into 2013?

Thomas C. Stabley

Well, it doesn't flow through into our liquids realizations. Our liquids realizations, when you look at them, are C3 plus stream only. So when we talk around being around 50% of NYMEX in Q4, that's really a result of the fact that 1/5 -- of our C3 plus stream, about 55% is propane, which is sold into the local markets. So none of our propane is being shipped out via Conway pricing. It's all sold at Mont Belvieu into the local markets, with transport costs being very minimal. Going forward, we would expect that same C3 plus stream to be transported down to MarkWest facility and get similar pricing. So I think for Rex going forward, somewhere between that 45% and 50% of NYMEX is what we would expect to see throughout 2013.

Gordon Douthat - Wells Fargo Securities, LLC, Research Division

Okay. And then one last one for me. Any opportunities to increase your acreage position from -- on the Ohio Utica side? I know you've kind of raised your 20,000-acre goal, but I don't know if you have any thoughts about growing that at all?

Thomas C. Stabley

Sure. We're continuing to look at opportunities everyday in the Ohio Utica positions. I think our existing positions, the one in Warrior North, the majority of that county is leased. There are some expiring leases that will have a chance to pick up, but I don't think it will be material. Our big opportunity in the Warrior North area is really doing some sort of an acreage trade with Chesapeake and [indiscernible]. They are the big producers -- or the other big acreage holders in that area, and I think if we can work some trades out with them, that will really add additional laterals and potential in that area. In the South, again, same situation. The majority of that acreage is leased up down there. I think there's a small amount that we can continue to try and get. So the big opportunity down there is really just to get units formed with other operators and then get in the position to be able to drill up what we have. And then continue to look at packages throughout the Utica and Ohio that may be opportunistic to Rex from a liquids prospective.

Operator

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

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

I got on your call a little late, so I apologize if you have addressed any of these questions, but it sounded like you've settled on the "Super Frac" design as kind of your typical well going forward for Butler County. And I want to verify that's in fact the case, and then not I'm sure if you mentioned the well costs for, say, a 26, 27 frac stage kind of well?

Patrick M. McKinney

Mark. It's Pat. No, we have. We've settled on the "Super Frac" design going forward in Butler for both the Marcellus and Upper Devonian. What we're still trying to sort out is the optimized stage spacing of -- we've done a couple wells of 225-foot versus 150-foot. And we're still looking at production performance to try to settle in on what is the optimal spacing between the laterals. We've gone from 950 feet, and some of the earlier ones were 500 feet. So we're trying to optimize that. But for the most part, the higher sand concentration "Super Frac" design is definitely what we're going to use going forward, both in Butler in the Marcellus and in the Upper Devonian, and also in Ohio.

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

And what's the typical well cost there now?

Patrick M. McKinney

We're still -- the last public information we had out there in Butler was $6.5 million. And as Tom mentioned earlier on the call, if we can get to some more pad drilling and get some more economies of scale, we might be able to cut that down another 5% or another 10% over time in full development mode.

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

Got you. And on the laterals that are 500 feet apart, have you seen much in the way of interference at this point?

Patrick M. McKinney

I would tell you that it's a mixed bag. In some of the wells, we've seen some. In other wells, we really haven't. But you're going to need a little bit more production history to do that modeling. So that's why we're testing the different spacing as we really try to settle in what works the best.

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

In the 56 wells you have in Butler now, can you say what percentage of your acreage at this point you feel like you're going to focus on developing for the next couple of years? It looks like you've pretty well de-risked maybe 3/4 of it just by eyeballing your map. But do you have of a better figure for that?

Thomas C. Stabley

Well, I think -- again, the acreage program that we've laid down now is an HBP program. I don't know that there's any of the area that we're -- in our core block that we're not planning on going to. I do know that later this year, we do have a well-planned in kind of the southeast corner of our acreage, which will give us a little bit more color kind of down in that area. And we do have a pad next year that's going to be a little bit more early next year in the northwest corner. But really none of those areas bother us or make us nervous about going in and drilling the wells.

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

Good. And then on the production guidance that you gave, it sounded like, from Michael's comments, the primary reason for that little dip in the first quarter is you're just bringing on fewer wells. Had you anticipated that all along? Or did something cause a delay in getting some wells on in the first quarter?

Michael L. Hodges

No, that was included in the full year guidance we had put out in our last release. So we know that, that would be a little bit flat in the first quarter, and I think we're looking forward to a pretty nice sequential growth when we get to the second quarter.

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

And are you seeing any sort of constraints at this point midstream or any others that are really holding back your production?

Thomas C. Stabley

As far as Butler goes, we've got the 90 million a day capacity. So we wouldn't expect to see any issues there until we get to the end of this year. But obviously, that's something we would have known in our forecasts. Of course, the next plant comes online in the first quarter of '14, so that will alleviate that pretty quickly. On the Ohio side, the only issue that we've experienced, similar to some other operators, is in the Warrior South area with our midstream provider getting those trunk lines in place to get that gas out. Our wells are done. Actually, the 60-day resting periods are over, so as soon as those lines can get in place, we're ready to take that gas to sales.

Operator

Our next question comes from Jack Aydin from KeyBanc.

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

Most as my questions were answered but I -- just this question on Illinois. Is conventional oil drilling horizontally, you think you might be looking a resource potential type of a play?

Patrick M. McKinney

Jack, this is Pat. I mean, the good thing about that basin is it's very mature and it's been drilled up since the early 1900s, so you got a lot as well control out there. And so we're really targeting the zones that have had some history of production that have been kind as either neglected or being able to now use modern completion techniques on -- to focus on. So most of the zones have been historical oil production intervals, and we're just looking at optimizing those. So it depends on your definition of a resource play, I guess. But most of the targets we're looking at are in or around areas that have had some historical oil production.

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

I assume you added leases. What is the lease cost over there? And what's going -- your costs per acres over there? And what is the market price right now going forward? You have an -- I'm sure you do have an idea.

Thomas C. Stabley

Sure, we have an idea, Jack. We have about 26,000 acres now in our legacy assets. We have started to pick up some additional leases in areas where we think we've seen success. But I don't think at this point, based on the competitive nature that we are seeing in the basin, that we're ready to talk about kind of what those costs are or how much we think we can get.

Operator

Our next question comes from Jeff Hayden from KLR Group.

Jeffrey P. Hayden - KLR Group Holdings, LLC, Research Division

A couple quick questions for you guys. One, I guess, kind of jumping back to the ethane, could you guys give us some modeling help as far as 2014 goes? Roughly what kind of shrink should we be looking for on the gas side? And then kind of barrels per million that the ethane is going to add? And then roughly what kind of production should we apply that to?

Patrick M. McKinney

Jeff, this is Pat. You've got to take a little cue from our proved reserve report, where we talk about the split of the C3 plus and the ethane. So you're looking at about 37 barrels per million well head for the C3 plus. And in total, including the ethane, it's about 111 barrels per million at the well head yields for what we've got out there. And it's about -- as we've gotten the proved reserve report, about 2/3 ethane.

Jeffrey P. Hayden - KLR Group Holdings, LLC, Research Division

And okay. And would kind as shrink factor should we use on the gas?

Patrick M. McKinney

It's going to depend. You're going to be in a range of between 10% and 15% depending on what plant it goes into.

Jeffrey P. Hayden - KLR Group Holdings, LLC, Research Division

Okay, that's helpful. Thanks. And just a little bit on the AFEs. What would the AFE run for, for the Drushel 6-HD?

Patrick M. McKinney

We've been pretty consistent, Jeff, in talking about that our 4,000-foot type curve type well is about 6.5 million. So that well's lateral length was right at about 4,000 feet, so it's going to come in pretty close to that. And as Tom had mentioned earlier, our goal was to try to get those costs down between 5% and 10% here as we can get some more economies of scale out there and maybe get to a little bit more pad drilling. But we're still in that range of $6.5 million.

Jeffrey P. Hayden - KLR Group Holdings, LLC, Research Division

Okay. So we should basically just assume that the Upper Devonian wells are going to be about the same as the Marcellus wells?

Patrick M. McKinney

Yes, it's only 250 foot shallower, so you're basically going to be on the wells the same amount of time.

Jeffrey P. Hayden - KLR Group Holdings, LLC, Research Division

Okay. And then I think you guys have previously provided guidance of about $9 million or kind of $8.5 million to $9 million, somewhere in that range, for the Warrior project. Does that assume "Super Fracs"? What should we think for the Warrior "Super Frac" AFEs?

Patrick M. McKinney

Yes, that does. We've talked about a 2013 at about 8.8 million, and that does include a full "Super Frac" on it. And obviously, we discussed that we've been pretty successful in reducing our drilling days. So again, our goal was to try to take that number down. And if we get some more well completions under that, we'll talk about it more in the future. But our goal was to take that down, but we're using $8.8 million right now for 2013.

Operator

Our next question comes from Leo Mariani from RBC.

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

Obviously, you had some successful wells in more of the Super Rich area in Butler using the "Super Frac." Wanted to get a sense as what the EURs are looking like on these wells.

Patrick M. McKinney

Leo, this is Pat. We're still in that 7 Bcfe range that we talked about that Netherland, Sewell has supported since our 10/31 reserve release for the high-yield deal, and that's with C3 plus at 9.7 with full ethane recovery starting in '14. So we're still there for our Marcellus. Obviously, we're pleased with the Upper Devonian production of the Drushel well, and it looks like it may be on par with the Marcellus from early results.

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

All right, that's helpful. And I guess, with respect to the last question on Utica well cost, you guys talked about targeting $8.8 million, and then you talked about reducing your drill times almost 20 days here. So what do you think those costs can go to, if you can guidance the system, let you kind of achieve those lower drill times?

Patrick M. McKinney

Well, I do think we're in a position yet to really go out and state the number out there. I think if we get a couple more wells down, maybe in the second quarter call, we'll be able to talk about what we're averaging there. But we are pleased. The first couple of handful of wells in the program, you're going to take your lumps, and I think we've really made some good strides on the drilling side. So our goal is to take that number down, but I don't think we're ready yet to kind of talk about where we think it's going to be. But we're encouraged by our progress on the last 4 wells we've drilled in Ohio.

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

Okay. And I guess your CapEx guidance for 2013, was that originally assuming that you would do "Super Fracs" in the Butler area for all your wells?

Thomas C. Stabley

Yes, it was. Yes.

Operator

Our next question comes from Ron Mills from Johnson Rice.

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

Tom, I'll take the bait on your new NOVA contract. You mentioned it a couple times. Can you provide some of the details or characteristics of the new 2,000-barrel-a-day ethane contract with NOVA and how it compares with the ATEX agreement?

Thomas C. Stabley

Yes. Ron, so the NOVA contract is a little bit different in the sense that they buy the gas at the tail end -- tailgate of the Houston facility, so there's really not a transport cost to get down to Mont Belvieu or to the Sarnia plants. We talked about $0.22, $0.21 to $0.23, to get the gas out on ATEX, and then we received Mont Belvieu pricing. Basically what we get on this contract is more like a gas price contract that's going to pay at the tailgate of the MarkWest plant.

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

Okay. And so ATEX was 3,000 barrels a day, NOVA is 2,000. Are they both starting up in the first quarter and so you can kind of see that impact for the full year?

Thomas C. Stabley

That's a good question, Ron. Both contracts are flexed so that they can be ready to go when the Y-grade line is put in place by MarkWest. So we've got flexibility on the start date for both of those. So we're really waiting on the MarkWest Y-grade line that's supposed to be in place during the first quarter of '14.

Operator

I'd like to turn the conference back over to Mr. Tom Stabley for closing remarks.

Thomas C. Stabley

Great. Thank you very much for everyone participating on Rex Energy's 2012 Full Year and Fourth Quarter Update, and we look forward to speaking with you during the first quarter call. Thank you.

Operator

Ladies and gentlemen, thank you for your participation in today's conference. This does conclude the program, and you may all disconnect at this time.

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 Management Discusses Q4 2012 Results - Earnings Call Transcript
This Transcript
All Transcripts