Penn Virginia Corporation
Q3 2014 Earnings Call Transcript

Published: 2 Nov 2014

[Operator:]

Good day, ladies and gentlemen, and welcome to the Penn Virginia Corporation’s Third Quarter 2014 Earnings Call. At this time all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time. (Operator Instructions) As a reminder, this conference is being recorded. I would like to introduce your host for today’s conference, Mr. Baird Whitehead, CEO and President. Sir you may begin.

[Baird Whitehead:]

Thank you very much, Sandy. And thank you all for joining us today for our third quarter 2014 conference call. I am joined today by members of our management team, including John Brooks, our Chief Operating Officer; Nancy Snyder, our Chief Administrative Officer; Steve Hartman, our Chief Financial Officer; and Jim Dean, our Vice President of Corporate Development. Prior to getting started, we would like to remind you the language in our forward-looking statements, sections of the press releases issued yesterday, as well as our Form 10-Q, which was filed last night. We are very pleased with the third quarter results. We exceeded the upper end of production guidance and delivered continued strong cash flows and margins for the quarter. The potential for production of reserve growth in the Eagle Ford is substantial, and we are well positioned within it considering our 104,000 net acre position that is blocky and contiguous. We have confidence in the excellent quality of this asset, including what we consider to be a significant potential in the Upper Eagle Ford. The third quarter production was 22,700 barrels a day equivalent a day, which was 4% higher than the second quarter, while on the Eagle Ford itself production increased 8% quarter-over-quarter to almost 17,000 barrels a day equivalent. Our IP rates continued to reflect increased productivity due to our transition to pad drilling over the past year and a half. Our operating wells had an average IP rate of 1,350 barrels equivalent per day and we have five notable wells with IPs over 1,900 barrels a day equivalent. These five wells included

[John Brooks:]

Thank you, Baird, and good morning. Baird has discussed our third quarter operational highlights in fair amount of details, so I will add just a few things. We have a substantial number of wells yet to turn in line in the fourth quarter. 12 wells are currently completing or flowing back, including six Upper Eagle Ford wells. We have 14 wells also waiting on completion, including another six Upper Eagle Ford wells. And eight operated wells are currently being drilled and three of those are Upper Eagle Ford wells. Overall, we expect to turn in line 33 operated wells, excluding shallow wells, during the fourth quarter of 2014, for an estimated total of 88 operated wells to be turned in line during 2014, excluding shallow wells. And this includes 18 Upper Eagle Ford wells. Our Eagle Ford acreage has an undrilled location inventory of approximately 1,600 locations. Approximately 600 of these locations are on the Upper Eagle Ford and over a 1,000 locations are in the lower Eagle Ford, with the potential for another 400 Upper Eagle Ford locations overlying our lower Eagle Ford in the Western Lavaca County area. In the third quarter, our average well cost was approximately $9.4 million overall, with our two-string wells averaging $8.5 million and our three-string wells averaging $10.2 million. On a per stage basis, total wells costs in the third quarter averaged $358,000 per stage. With the two-string wells averaging $348,000 per stage, and three-string wells averaging $366,000 per stage. Total proppant pumped averaged approximately 10 million pounds per well. For the 17 wells we turned in line in the quarter, the average amount of proppant pumped was approximately 368,000 pounds per stage or approximately 1,700 pounds of proppant per foot of lateral. We averaged 4.4 frac stages per day per pad during our stimulation operations in the third quarter and that contributed to our exceeding guidance production in the third quarter. We’ve refitted two of our drilling rigs with 7,500 PSI fluid ends on their mud pumps, which yields additional hydraulic horsepower resulting in faster drilling ROPs. A third refit underway and a fourth refit is expected to be complete by January 2015. For the first half of 2014, utilizing these and several other innovations, we’ve increased our effective footage drilled per day by 17% as of October, compared to 2013. We are in receipt of our service providers to stimulation contracts for the next 12 months, and they are under final review. These contracts were one year pricing arrangements and we are confident that any unit cost increases will not be substantial and can be mitigated by the improvements we have made in the optimizing completion design. Additionally, the contract terms were flexible enough to keep us from being locked in to out of market prices. Looking forward, the most significant drivers for further cost reduction will be continued efficiency gains, both in drilling and completion. On the drilling side, it’s possible we can further reduce time and location by two or more days per well with the increased ROPs mentioned earlier. And on the three-well pad that could save a week’s worth of time and money. On the completion side, we continue to optimize our frac designs, which ultimately results in completing more stages per day at a lower cost. While we averaged 4.4 frac stages per day in the third quarter, it is not uncommon for us to achieve six and seven stages per day. Sustaining that pace of execution is the challenge. And that concludes my operational update. And at this time, I’ll turn it over to our CFO, Steve Hartman.

[Steve Hartman:]

Thanks, John. The financial results are summarized in the release, so I won’t go through that detail. But as Baird stated earlier, we are pleased with our strong cash flow and margins for the quarter. I would like to highlight our lease operating expenses for the quarter though [ph]. It was higher than our typical run rate. We had some one-time work-overs and a catch-up charge for compression expense that made our per unit cost higher than usual. We are still comfortable with the run rate per unit cost of about $5 to $6 per BOE going forward. With that, I’ll just move on to our capital resources and liquidity. As of the end of the quarter, we had a $124 million of cash on the balance sheet and we have a credit facility borrowing base of $500 million. Our pro forma total liquidity was $622 million, net of letters of credit. We brought in $250 million of cash during the quarter, $215 million of that was from non-core asset sale proceeds and $35 million was the final arbitration cash settlement, related to our acquisition of Eagle Ford properties in April 2013. None of these proceeds required any pro forma adjustment to our trailing 12-month EBITDAX for calculating our leverage ratio. So our leverage improved significantly this quarter. We’ve reported leverage of 2.6x for the quarter compared to 3.1x at the end of the prior quarter. And if you annualize our third quarter EBITDAX, our leverage is 2.4x. Our credit facility which matures in 2017 is completely undrawn at this point. Our two publicly traded bonds mature in 2019 and 2020. We have no debt maturities for the next 2.5 years. This combination of no near-term maturities and ample liquidity gives us the flexibility to adjust our drilling programs in response to the current industry conditions, and we are confident in our ability to continue to do so, should the current downturn persist. Now looking at our guidance update. We are increasing our 2014 CapEx guidance to $754 million to $800 million. This implies fourth quarter guidance of $197 million to $243 million. At this time, we are planning to run the eight-rig program through the quarter. We expect to turn in line 31 gross and 21.2 net wells. The higher CapEx is tied to the higher steel costs associated with our transition to 5.5 inch casing in Lavaca County and just generally higher completion costs. We expect well costs will come down in 2015, with continued lower commodity prices, but we are not planning for these cost reductions in the fourth quarter. We are also raising our land guidance slightly based on leasing activity we saw in the third quarter, but I wouldn’t expect us to be very aggressive in adding land in the fourth quarter, mostly just adding land for drilling units in our current footprint. We are reaffirming our production guidance for the year at 8.4 to 8.6 million barrels of oil equivalent. That implies fourth quarter production of 2.4 to 2.6 million BOE or 25,900 to 28,200 BOE per day. At the midpoint of guidance, this is almost 20% sequential increase. For our oil production, we are guiding to 4.9 to 5 million barrels of oil. That implies fourth quarter production of 15,850 to 16,935 barrels per day. At the midpoint of guidance, that would be a 21% sequential increase. For adjusted EBITDAX, we are decreasing our guidance in response to lower commodity prices to a range of $387 million to $427 million. This implies fourth quarter guidance of $100 million to $140 million. This assumes a WTI oil price of $82 for October and $80 for November and December. Our volumes are well hedged for the fourth quarter, and through 2015 for that matter. For the fourth quarter, we have 13,000 barrels of oil per day hedged, which is 79% of the midpoint of guidance at a weighted average floor price of $92.92. The hedges are doing their job of protecting our cash flow. If WTI averages $80 for all of the fourth quarter, we will receive $15.5 million in cash proceeds. As I mentioned earlier, our liquidity remains strong. We expect to end the year with nothing drawn on the credit facility, liquidity of approximately $500 million, and leverage of around 2.6x to 2.7x. With liquidity of $0.5 billion, leverage below 3x, and hedges on 13,000 barrels of oil per day in the first half of 2015, and 11,000 barrels of oil per day in the second half of 2015, we are confident in our ability to fund the drilling program that enables us to grow production and grow cash flow in 2015, while generating appropriate returns in driving shareholder value. We look forward to providing details on the 2015 plan in December or early January. And Baird, that’s it for the financial review.

[Baird Whitehead:]

All right, thanks Steve. Sandy, we’re ready to go ahead and take questions please.

[Operator:]

(Operator Instructions) Our first question comes from the line of Neal Dingmann of SunTrust. Your line is open.

[Neal Dingmann:]

Good morning guys.

[Baird Whitehead:]

Hi Neal.

[Neal Dingmann:]

So, Baird, obviously question is going to be on just sort of when you look at spending for next year, including if you’re able to pursue that stock buyback, how – I guess a question for you or for Steve. How do you guys think about sort of that as part of your spending, or how are you going to sort of integrate that? I’m just sort of wondering on a total spend which I would – to me, I guess I’m including if you buy some stock back, how you, sort of, look at that? So I guess the two part question. One, would that just be a total part of – if you’re going to spend, I don’t know, 5% or 10% less next year, would that include if you add some stock buyback on that? And then secondly, just how – I guess, when you come up with that plan in the later part of this year based on pricing, is there a certain level, kind of from a debt to EBITDA or some other metrics that you want to stay behind as far as that spending goes?

[Baird Whitehead:]

Neil, at this time really it would be – any decision we may make on share buyback would just be part of our overall optionalities, part of our CapEx program. Sit back and look directionally to see what oil prices are doing. We’ll take into account the returns we could generate with those kind of pricings. And we’ll also weigh within that analysis of the option to buy back some shares, but it would be all inclusive. It would not be coming up with something and then adding a share buyback on top of it, if that makes sense. We’d deal within a certain total range of CapEx in either allocated to all drilling, allocated to part of share buyback or drilling or various scenarios. But at this point, we’re still working through what we’re going to do, but that would be our logic

[Neal Dingmann:]

That makes sense. And then secondly, question for you or John. Just looking at plans for next year – and obviously I think in the press release where you outlined just some of the different IP and 30-day rates, when you look at either the Beer Quad or some of the Rock Creek, Bozka area and some of the higher areas. How does that factor in where you’ll drill next year? I mean is it just simply you’ll go after just the best areas, or is there still a fair amount of leases you have to hold. How should we think about now with over 100,000 acres attacking that next year?

[Baird Whitehead:]

We would focus on the best areas. If we don’t have a big lease expiration problem, it would cost us I think roughly $5 million to extend leases if we slowed down drilling a lot, that’s not our intent at this time, but I’m just giving you some what-ifs, but the lease expiration is not a big problem and the money to extend those leases is not a lot of money. So we have a lot of flexibilities. So to answer your question, we’re going drill the best things we can, whether that’s the Beer Quad, whether that’s up in Peach Creek, whether that is Upper Eagle Ford based on what we learned here in the second half of the year. We have various opportunities and we think they are all good.

[Neal Dingmann:]

That makes a lot of sense. And then lastly, obviously there is still some concerns just on execution, etcetera, just right there on the operation. So I guess my question is, you mentioned the larger case, different things around that, doing some of these and some of the efficiencies that John mentioned, just your confidence level of execution because of some of these different advances now that you’ve put into place how you look at that going into 2015, if you think you’ve solved a lot of the issues that you had earlier this year?

[Baird Whitehead:]

Yes. And I’ll let John answer some of this too of course, to give you some more detail, but yes, we’re getting better at it over time. Even on the 4.5 completions, we’re getting better at it. So John, why don’t you give a little more detail on what we’ve done to improve things?

[John Brooks:]

Sure. We’ve improved the operational execution by making some adjustments in our completion procedures. To give you some details, we’ve modified our pump down procedures with more tightly controlled pump rates and tool string velocities to better accommodate a specific well bore trajectory. We geosteer these wells in a fairly tight window, so we could loosen that window and make things easier for ourselves and then model if beforehand to make sure we’re pumping at the right rates and pressures to minimize risks. The other thing is adjusting the fluid rheology and the flush volumes following our proppant placement, which basically entails pumping gel sweeps to flush the well bore clean sand following the proppant laden slurry at the frac stage. This is in itself is a particularly new, but what we’ve done is more tightly engineered the sweeps specific fluid properties and volumes to ensure there is no sand left in the well bore to minimize the mechanical risk of both running in the hole and pulling out of the whole. Another area where we’ve made some significant improvements is in our coiled tubing drill out. As we stated before, Penn Virginia provides its own drilling fluids and fluid engineers, and we had extended that to provide the engineering fluid support on our coiled tubing drill outs. This has reduced our average time for coiled tubing drill outs to less than two days per well. And then there is a host of several other details, but all of that just combines to give you more stages per day at lower cost.

[Baird Whitehead:]

We’re getting better at this all the time, and we’ve seen a lot of improvement. And when we say when we continue to do better over time, our goal is to get to that six to eight stages per day per pad would be our goal.

[Neal Dingmann:]

Definitely sounds like a lot of improvements. Thank you all. Keep up the good work.

[Baird Whitehead:]

Thanks Neil.

[Operator:]

Thank you. Our next question comes from the line of Brian Corales of Howard Weil. Your line is open.

[Brian Corales:]

Good morning. Just a couple of quick questions. One is the backlog. Is that a normal backlog, is that higher than normal, how should we think about that?

[Baird Whitehead:]

John, why don’t you – it’s probably higher than normal.

[John Brooks:]

Well, in the previous quarter, it was higher than normal. I think we’ve got it – internally we’re tracking a completion inventory at the end of third quarter of about 15 wells left to complete. Maintaining a certain amount of inventory is beneficial for your completion crews’ efficiencies. So that you can make sure you utilize all your crews and still have time to sharp their equipment. So I think basically having about 12 to 15 on a rolling basis is probably what we’re going to shoot for, just to make sure that we’re utilizing everything as sufficiently as possible.

[Baird Whitehead:]

Just to add one thing, Brian, one of the key things that we have done and we’re trying to do to solve some of the execution problems, trying to keep the same people out on the location all the time. That means getting enough of backlog in order to do that, but we think that’s extremely important versus having new people show up all the time. So right now we have three fractures running. We expect a fourth here, help me out John.

[John Brooks:]

[indiscernible].

[Baird Whitehead:]

So we’ll have four ranges [ph] to get caught back up somewhat, but we’re extremely busy on the completion site right now.

[Brian Corales:]

Okay. And then, I know you probably don’t know fully this answer, but can you maybe just ballpark how much of the 104,000 acres is prospective for the Upper Eagle Ford, and then how much of that 104,000 acres could have, both upper and lower?

[Baird Whitehead:]

I would say about roughly half of the prospective for the upper – based on what we’ve tested so far, there is some additional testing to be done to the northwest up in Peach Creek, that can test some other more northernly Upper Eagle Ford opportunities, which hopefully we get to hear in the fourth quarter or early first quarter. Then there is probably about a third of it that’s prospective from both.

[Brian Corales:]

And thus far against you haven’t seen any communication between upper and lower testing when tested?

[Baird Whitehead:]

I mean based on what we have seen on the flow-backs based on how these things act, their initial production, that’s flat. As I said, inclining in some cases. Is as completely different than the lower. I mean typically you can establish peak rate on the lower in a very short period of time, because the water [indiscernible] substantially in a short period of time. So it acts completely differently on the flow-back and the early production profiles of these things. So I think nothing is ever slam dunk, but what we have seen so far gives us quite a bit of confidence they are acting as two separate reservoirs, Brain.

[Brian Corales:]

Okay, guys. Thank you so much.

[Baird Whitehead:]

All right, thank you.

[Operator:]

Thank you. Our next question comes from the line of Steve Berman of Canaccord Genuity. Your line is open.

[Steve Berman:]

Thanks, good morning. John, you gave some good details on the cost, and you may have said this and I might have missed it, but are you seeing any appreciable differences between and Upper and Lower Eagle Ford wells, maybe just say on a per stage or per foot basis in terms of completed well costs?

[John Brooks:]

I think on the Upper Eagle Ford, the major difference is you’ve got more primary perm and porosity, so we end up with lower treating pressures. That’s also allowed us to put away more sand volumes and also higher slurry densities as well. So on a unit cost basis they’re probably identical, but we’re able to put more sand volume away and get higher slurry densities by and large in the Upper Eagle Ford.

[Steve Berman:]

And then looking at the Welhausen and Martinsen wells after roughly a half a year online, the 52% and 54% oil cuts. Is that kind of where you expected it to be, higher or lower, can you just talk about the hydrocarbon mix relative to your expectations?

[Baird Whitehead:]

I’d say they may be slightly higher gas than we had expected, trying to get an update over in eastern part of our acreage. As you go to east, the GOR in general weighting for the lower gets higher. I would say maybe slightly gassier, but I don’t think there is a big difference at this point in time, but the lower versus upper in the same geographic area. I’d say they’d be pretty close.

[Steve Berman:]

Okay. And then, Baird, what’s the timeline on possibly getting the approval from the banks on the stock repurchases. Is that days, weeks? I just want to get a sense of how long that might take.

[Steve Hartman:]

Steve, this is Steve. It will probably be about three weeks. It just went out to the bank group in the last couple of days, so it will take a few weeks.

[Steve Berman:]

Okay. Great, all right. Thanks guys.

[Baird Whitehead:]

All right. Thanks Steve.

[Operator:]

Thank you. Our next question comes from the line of Scott Hanold of RBC. Your line is open.

[Scott Hanold:]

Good morning guys.

[Baird Whitehead:]

Hi Scott.

[Scott Hanold:]

Baird, you talked a little bit about some of the Upper Eagle Ford tests that hadn’t been cleaned up, the Netardus wells if I pronounced that correctly. I don’t know if you or John could kind of give us a sense of, when you look at the Martinsen and Welhausen, how long did those take to cleanup before they hit their peak rates? So when you look at the Netardus wells, where do you think they compare relative to kind of those two wells?

[Baird Whitehead:]

If you look at the margin we actually have in our public presentation, there is a slide that shows the performance of the Welhausen and the Martinsen wells. The Welhausen had somewhat of a higher initial decline than Martinsen well. There was very little decline, and in fact this about as flat as you can see it at this point in time I think on the Martinsen, whereas the two have actually crossed, the Welhausen and Martinsen. If I had to rank how the Netardus #2, forgetting the #3 at this time because of the down hold restriction and the Welhausen wells, the #7 and #8, I’d say that they maybe just a step below the Martinsen at this time, but I don’t think it’s a big step. As I said, mid-year we put about a million barrels equivalent on both the Martinsen and the Welhausen #2 and there was room to take it up even further. So there is probably a good reason how these things, why these things are acting fairly flat early on because of the natural fractures in the upper and the fractures you’re introducing is just causes a much more efficient cleanup. And I think that’s why it explains how these things are flattish or even increasing over time. So the Welhausen – I think its Welhausen #7 is increasing as we speak and Netardus #2 continues to get better. But I realize that’s a lot of words to try to explain this, but if they are below the Martinsen and Welhausen, I don’t think they are a lot below those two.

[Scott Hanold:]

Okay, so still very strong wells. And typically how long does it take from initial flow-back to clean those things up?

[Baird Whitehead:]

Yes, I don’t – at the Martinsen, because it’s flat, I’d say it’s still cleaning up even after five, six months. So that’s a tough question to answer, because these wells are making a lot of water, and I’m talking about couple of thousand barrels of water a day and you pump over, I don’t know, 150,000 barrels of water in total or more, it would take some time but they continue to improve. It’s ever so slightly you have to put on a graph to see it, but it continues to get better over time. So again it’s a tough question to answer, but I’d say it takes an appreciable amount of time to ultimately get these things cleaned up.

[Scott Hanold:]

Okay, understood. And then I know you are going to discuss 2015 capital budget in more detail mid-December. Let me ask you a question in a little different way, see if I can get at what I’m looking at, but when you had ramped up the eight-rig, what kind of oil price did that assume. So was it sort of in that range of where we’re at right now? And when you look at your 2015 capital budget decision, how does the weakness in oil price make your opinion differ from that level?

[Baird Whitehead:]

Well, the eight-rig program was based on $85 WTI. So we’re roughly in the $80 range now with directionally being concerned about where oil prices may end up, and who knows where they end up. Is it $75 or $70, I don’t know at this time, but we want to be confident where oil prices are heading before we put anything out there guidance-wise is really the answer to that question, Scott.

[Scott Hanold:]

Okay. And for maybe Steve, like when you look at your hedge portfolio into next year, where do you – like on incremental hedges adding right now at this point, where do you want to be coming into the beginning of next year, and where are some of you more recent hedge positions been layered in at?

[Steve Hartman:]

We feel pretty good about our hedge position right now, Scott. We have 13,000 barrels hedged for the first half and 11,000 barrels hedged for the second half. It’s all over $90. We haven’t hedged really anything below $90. So it’s been over a month since we last layered into 2015. So right now in the current environment, we’re not looking to add hedges at all. We might look forward in 2016 at some point, but right now we’re just kind of holding back and seeing where oil prices settle out.

[Scott Hanold:]

Understood, thank you.

[Baird Whitehead:]

Thanks Scott.

[Operator:]

Thank you. Our next question comes from the line of David Tameron of Wells Fargo. Your line is open.

[David Tameron:]

Yes, good morning. A lot has been asked Baird, but can we get back to – you mentioned the natural fractures as far as the Upper Eagle Ford versus the lower. Is there anything else going on as far as the geologic, just the quality of the rock that you’re seeing a difference? Do you see any big noticeable differences between the two?

[Baird Whitehead:]

Well, we have some open hole logs in some sidewalk cores, some of the test holes we drilled through both the upper and the lower. Primary proxy-wise it’s about the same as the lower. It’s much more calcareous than the lower, even though you could characterize it as the shale. You could also characterize it may be approaching more so of a unconventional, I hate to use word tight sand, but you could more refer to it as an unconventional tight sand kind of reservoir than a resource, even though it’s still in a resource category. It’s probably the best way to answer that question, David.

[David Tameron:]

Okay, that’s helpful. And then what kind – are you guys using resin coated sand, or are you doing any tailing in, or what exactly is your completion technique right now that you’re most comfortable with or that you’ve seen the best results from?

[Baird Whitehead:]

We’re using a hybrid design that we will start off with slick water on our fluids that will grade over to a linear gel. And then towards the end of the stage, go to a cross-link gel. On the proppant side, once we get our pad pumped, we will start pumping 100 mesh and then go to white sand and then tail-in with the last 50,000 or 60,000 pounds of resin coat. And the primary difference is in our three-string wells. The sand we’re – or the proppant we’re using is 30/50 and in the two-string areas, it’s 20/40. What we have found is in the Upper Eagle Ford even in our three-string areas, we’re often able to get some 20/40 away at the higher slurry densities. So typically we would end up with maybe three pound per gallon of final slurry density, but in the Upper Eagle Ford, we’re often ended up at four pound per gallon apparent or higher.

[David Tameron:]

Okay, that’s helpful. And then just one more. Baird, getting back to the 2015, how should or how is the board going to frame the argument or how are you guys going to frame the argument of share buyback versus capital spend for 2015 and development progress? How should – can you give us any color about how you guys are going to make that decision?

[Baird Whitehead:]

No, not really at this time. Really the share buyback is just another option we wanted to get in place. Importantly just going to compete for capital like drilling wells, at the same time we want to grow production, we want to grow reserves per share. We want to maintain sufficient liquidity to exercise our program – execute on our program. So in any case, at this time, I can’t give you any specifics.

[David Tameron:]

Okay.

[Baird Whitehead:]

But that’s sort of how we’re going to do it.

[David Tameron:]

All right. Even that’s helpful, so I appreciate it. Thanks.

[Baird Whitehead:]

Okay, thank you.

[Operator:]

Thank you. Our next question comes from the line of Welles Fitzpatrick of Johnson Rice. Your line is open.

[Welles Fitzpatrick:]

Good morning.

[Baird Whitehead:]

Hi Welles.

[Welles Fitzpatrick:]

The Netardus wells, if I’m looking at them right, it seem like they’re right between the Welhausen and the Martinsen, but the GOR seem a little bit lower. Is that typical at this stage of flow-back, or do you think that’s going to persist over the life of the well?

[Baird Whitehead:]

These Netardus wells are actually west, if memory serves me correct, not a lot west, but they are west. The GORs are somewhat lower because static or subsurface depth-wise, you would expect to be somewhat less as you go to the west. I think there is also unknown because of the cleanup issue. It would not be uncommon or something like this where your gas to actually be a higher GOR initially, because it’s easier to break-through your water than with the oil would be. So I would not read a lot into the GOR at this time until we get more production history.

[Welles Fitzpatrick:]

Okay, perfect. And then what – did you guys say the stage count on those two wells?

[Baird Whitehead:]

We did not, but John do you know what they were, I can’t remember? Not off the top of my head.

[John Brooks:]

26, 27.

[Baird Whitehead:]

There you go.

[Welles Fitzpatrick:]

26. Okay, perfect. Thanks. And then just one last one, the lower per acre price. Is that a function of you guys moving a little bit more towards areas that are prospective mostly for the upper, or is that just a response to folks leasing lower for lower oil prices?

[Baird Whitehead:]

I would characterize it as, since our acres position is so contiguous and blocky, it actually gets – it gets a little bit easier and a little bit cheaper because of that reason. That’s how I would characterize it at this time.

[Welles Fitzpatrick:]

Okay, perfect. Thanks so much.

[Baird Whitehead:]

All right. Thanks Welles.

[Operator:]

Thank you. Our next question comes from the line of Kim Pacanovsky from Imperial Capital. Your line is open.

[Kim Pacanovsky:]

Hi, good morning. I’m just wondering, what percent of your acreage that is prospective for the Upper Eagle Ford would be de-risked with the rest of the 2014 program, the 11 wells that are planned, assuming they’re all successful?

[Baird Whitehead:]

I’d say – I can’t give you an exact percentage. The only reason I can’t is because that acres we bought here we announced I think back in July, we need to get some wells drilled on it as you go into the west and east [ph], but out of the 50% that John mentioned, I’d say probably 85% of that 50% would be de-risked with this program in the second half of this year. That’d be an estimate.

[Kim Pacanovsky:]

Okay. Because just looking at your map, they’re all in kind of a fairly tight band.

[Baird Whitehead:]

They are, but as you go to the west in the Gonzales County, the potential of the upper deteriorates.

[Kim Pacanovsky:]

Deteriorates.

[Baird Whitehead:]

Yes. So it’s primarily from the Gonzales-Lavaca County line.

[Kim Pacanovsky:]

Okay.

[Baird Whitehead:]

Eastern to the north. So everything in Lavaca County, we think is prospective in the upper.

[Kim Pacanovsky:]

Okay. And then just one final question. If I look at your 17 wells that were gross wells that were completed in this quarter, can you just give us a lay of the land of where those wells were drilled, in which areas, and also assuming that the high rate wells that you discussed are all in the Beer Quad or Rock Creek, is that correct, or were there any outliers in some of the other areas?

[Baird Whitehead:]

John, can you…

[John Brooks:]

Well, just looking at our – say, the Cinco J Ranch is probably one of the best wells we’ve drilled at the Gonzales County. We IP-ed it 2,600 BOE per day and most of that was oil. That is actually in our Rock Creek Ranch area, what we call our Bozka acreage that is it’s going to be over on the western half. And then a little bit south of that we had two more are L&J Lee units that each tested over 2,100 barrels of oil equivalent per day. And then we had quite a few in the Beer Quad, the Kosmos and the Porters. And then we had four more in what we call the zoo area, the Leopard Hunter in the upper part of prior Magnum Hunter-Peach Creek acquisition that are named after various animals. So those four there, and then we had two more shallow wells that were drilled down in southwest Gonzales County that are not part of our contiguous acreage in the core of our acreage.

[Kim Pacanovsky:]

Are those Hunter wells or near the Hunter [ph] wells?

[John Brooks:]

No, these are wells we have 100% up in north southwest Gonzales County that are quite a bit shallower.

[Kim Pacanovsky:]

Okay, all right. And then also just the Cinco J Ranch, wasn’t that announced last quarter?

[John Brooks:]

It was, but it was actually a third quarter well that we had some preliminary...

[Kim Pacanovsky:]

Got it. Okay. All right, great. Okay, thanks guys.

[Baird Whitehead:]

All right. Thanks Kim.

[Operator:]

Thank you. Our next question comes from the line of Gail Nicholson of KLR Group. Your line is open.

[Gail Nicholson:]

Good morning gentlemen. I was curious, looking at the Welhausen and Martinsen Upper Eagle Ford wells, what is the three-string compositional mix of those?

[Baird Whitehead:]

Well, that’s the casing. We a surface pipe down to roughly 3,500 feet, which is thirteen to three-eighths [ph]. We run nine to five-eighths [ph] to the chock if we drill in Lower Eagle Ford, if we drill in Upper Eagle Ford, it’s actually a little bit shallower than the chock. And then we run up 5.5 production pipe. So that’s how we come up with the three-string terminology.

[Gail Nicholson:]

No, I’m talking about three-string. So it’s 42% and 54% oil. What’s the NGL and gas composition?

[Baird Whitehead:]

On the Upper, it’s around 52% oil. I think the NGLs are around, help me out here, 25% and the rest of would be rest of the gas.

[Gail Nicholson:]

Okay, great. And then looking at the third quarter versus the second quarter completions, it looks like there is about a 10% increase in lateral length and I was curious, when we look at the fourth quarter wells to be turned online, the lateral length be closer to the three-quarter that’s over 6,000 feet, or would be closer to that 5,500 feet in the second quarter?

[Baird Whitehead:]

I think it will be closer to third quarter.

[Gail Nicholson:]

Okay, great. And then just one lastly, when we look especially at the Welhausen area, the additional Upper Eagle Ford wells you guys are drilling there, are you changing any of the completion techniques to try different designs to see if a different design might work better or worse, or are you doing the same design across that entire area?

[Baird Whitehead:]

Well, the initial wells that we completed out there used about 350,000 to 375,000 pounds of proppant per stage. What we’ve changed now is going to more sand putting away closer to 400,000 pounds per stage. And we’re actually putting one more Lower Eagle Ford well in that mix as well, because we think that has the added benefit on the zipper frac, extending the frac height throughout the whole Eagle Ford section.

[Gail Nicholson:]

Okay, great. Thank you.

[Baird Whitehead:]

Thanks Gail.

[Operator:]

Thank you. Our next question comes from the line of Adam Michael of Miller Tabak. Your line is open.

[Adam Michael:]

Hi guys. If I’m looking at your F&D costs at $80 oil, in your presentation it says it’s about $23 to $28 of BOE. And then I look at possibly buying back stock here at the current capital structure, I’m coming up with something around $17, $18 a BOE. It makes a lot of sense. Am I looking at this in the right way?

[Baird Whitehead:]

I guess that’s the way to look at. I mean I’m reluctant to answer the question, because at this point in time we haven’t made a decision what we’re going to do. So we have to take this all into account. Taking into account F&D and those kind of things and just kind of value of buying shares versus performing drilling programs. So I think that’s how we’re going to look at it.

[Adam Michael:]

Okay. And in case if I get up to that $23 a barrel on F&D, I could buy stock all the way up to $14, and I’m just trying as an analyst to figure out does it make sense and it appears it does, but if we’re looking at this in the right way?

[Steve Hartman:]

Adam, this is Steve. It is, like Baird said, one of the concerns but at the end of the day, we don’t get cash flow or production support from buying back stock. So we would also have to look at the overall picture company-wise and what we’re doing on our production profile and our cash flow, plus we will be limited by the banks and what we can do. So we’re got to take a lot of things into account, not just the financial metrics, but we will definitely be looking at all of that when we make decisions.

[Adam Michael:]

Okay, that’s helpful. Thanks guys.

[Baird Whitehead:]

Okay, thank you.

[Operator:]

Thank you. Our next question comes from the line of Richard Tullis with Capital One. Your line is open.

[Richard Tullis:]

Hi, good morning everyone.

[Baird Whitehead:]

Hi Richard.

[Richard Tullis:]

A lot has been covered already. I just wanted to go back to the third quarter completions again. So you had the longer laterals on average and associated more prop and frac stages. What accounts for, say the drop in average IP per lateral foot, compared to prior quarters? I know you’ve had some really good wells in there. Where there is some that were particularly low for the quarter, what were the main drivers there?

[Baird Whitehead:]

Well, I mean you always ask some lower wells. We are talking with Kim about those couple of wells in Culpepper down in the southwest part of Gonzales County. They have lower IPs but the drilling completion costs are significantly less. So the economics are just as compelling, but it just has a lower IP. It also has a lower decline rate associated with stuff down there. So there are some shallower wells that did have some effect on lowering the IP rate per lateral foot, but in general, we still think the economics are solid. Some of the wells we had lower IPs or cheaper wells drilled and complete also.

[Richard Tullis:]

Okay. And Baird if you could, recap the two Netardus well rates that you had mentioned early in the call please?

[Baird Whitehead:]

Netardus #2 is making around 650 barrels a day and almost 2 million and continues to increase as it cleans up. The Netardus #3, which had the down hold restrictions, we’re going to get back and then get it out in time. It’s restricted at roughly 250 barrels a day and about 900 Mcf a day, but it’s flat. I think based on where the restriction is, the well would be as good, if not better than the #2 well, but we got to go back and get it out and we’ve been successful doing that at another wells. There is no reason not to do it. Sometimes you’re better off doing when the pressure comes down somewhat on these wells for safety reasons and cost reasons. So we’ll do that at the appropriate point of time.

[Richard Tullis:]

Okay. And then just lastly, what’s the current outlook on potentially monetizing the Granite Wash assets, are you guys just going to – it looks like you’ll just retain those assets and produce them out?

[Baird Whitehead:]

That’s correct. At this point in time we’ve essentially discontinued talking to anybody. We didn’t get the expectation we were looking for. So considering it’s still generating $20 to $25 a year – $20 million to $25 million a year of EBITDAX we feel at this point in time. We just hang on to it and just minimize any expenditures on it, minimize LOE and later run scores.

[Richard Tullis:]

That’s all. Thanks a bunch.

[Baird Whitehead:]

All right. Thank you.

[Operator:]

Thank you. Our next question comes from the line of Sean Sneeden of Oppenheimer. Your line is open.

[Sean Sneeden:]

Hi. Thank you for taking the questions.

[Baird Whitehead:]

Good morning.

[Sean Sneeden:]

Most of them were already answered, but maybe just kind of follow-up on the question around CapEx. And Steve, maybe you can talk me through high levels, how any changes for 2015 might impact your thoughts on free cash flow neutrality by 2017.

[Steve Hartman:]

We haven’t gotten to that point, where we want to talk about 2015 yet. So that’s always one of those goals that’s in the back of our mind, but we’re not ready to comment on that yet.

[Sean Sneeden:]

Okay, sure. Understand. Would it be still fair to say that you’d want to – so I think you said previously you want to keep a minimum amount of liquidity, and keep I think leverage in check, would it be fair to say keeping leverage under 3x is still a relative priority for you, as you set your budget?

[Baird Whitehead:]

Yes. I’d say that that is a very primary goal as we look at the budget. Yes, that and the liquidity. We’ve been saying publicly that we want to keep at least $150 million to $200 million in liquidity and that’s still an important goal for us.

[Sean Sneeden:]

Okay, that’s great. Thank you.

[Baird Whitehead:]

All right, thank you.

[Sean Sneeden:]

If I can squeeze one more in.

[Baird Whitehead:]

Okay.

[Sean Sneeden:]

How do you guys – you guys talked a little bit about buying back shares, how would you think about buying back bonds to the extent their trading so far?

[Baird Whitehead:]

We would probably not do that at this point. I think it would be either investing in the drilling program or possibly buying back shares, but I don’t see us buying back bonds at this point.

[Sean Sneeden:]

Okay, great. Thank you very much.

[Baird Whitehead:]

All right, thank you.

[Operator:]

Thank you. Our next question comes from Biju Perincheril of Susquehanna. Your line is open.

[Biju Perincheril:]

Hi, good morning. One quick question, going back to the Upper Eagle Ford. Baird, do you guys have a view on how the drainage area differs, if at all, from what it is in the lower?

[Baird Whitehead:]

As far as spacing, we have not nailed that down at this point in time. We don’t think it’s any different than what the lower would be. There could be a case that you might be able to widen them out somewhat because it’s a different kind of reservoir, but we need to get into the heart of our exploitation program on the upper to fine-tune that spacing issue. But I’d say since it probably has better permeability than the lower, there is a case we made that you could probably widen them out and improve your economics and improve your reserves, all the good things that you would get with doing those kind of things. So yet to be determined would be my response at this time, Biju.

[Biju Perincheril:]

Okay. Are the Netardus wells, the closest you’ve drilled, and can you say how far apart those two were?

[Baird Whitehead:]

They were 400 feet. Is that correct, John?

[John Brooks:]

Yes.

[Baird Whitehead:]

So they’re close.

[Biju Perincheril:]

Okay, great. Thank you.

[Baird Whitehead:]

All right, thank you.

[Operator:]

Thank you. Our final question comes from the line of Phillip Pennell of Mariner. Your line is open.

[Phillip Pennell:]

Thanks for taking the question. The water cut, Baird that you talked about in the upper. Does that create a problem at all in terms of take away or treatment issues?

[Baird Whitehead:]

No, I don’t think so. In fact since we’re actually building a water collection system, I’d say it will probably help our overall reuse of flow-back water, since these wells are bringing back a lot of water in a shorter period of time. So no, really I think it’s going to be a catalyst for our new water collection system and water treatment system we’re putting in right now.

[Phillip Pennell:]

That’s the bump-up to $5 million from $3 million on the kind of logistics and treatment etcetera, that you guys talked about in the press release?

[Baird Whitehead:]

Exactly.

[Phillip Pennell:]

Okay. And then my last one is, where do we end the year with, in terms of net wells in operation in the Eagle Ford?

[John Brooks:]

I guess 300 probably [ph].

[Baird Whitehead:]

300. Was the question, total number of wells?

[Phillip Pennell:]

Yes, net wells.

[Baird Whitehead:]

At just the Eagle Ford?

[Phillip Pennell:]

Just in the Eagle Ford.

[Baird Whitehead:]

Yes, I’d say it’s probably pretty close to 300.

[John Brooks:]

Gross.

[Baird Whitehead:]

Gross.

[Phillip Pennell:]

300 gross. Okay.

[Baird Whitehead:]

Yes, if you want to estimate the net, I’d take 75% of it or so.

[Phillip Pennell:]

Right. Okay. Great, thanks, guys.

[Baird Whitehead:]

Okay, thank you.

[Operator:]

Thank you. At this time, I’m showing no further questions in the queue. I would like to turn the call back over to Mr. Baird Whitehead for closing remarks.

[Baird Whitehead:]

If there were any people who didn’t get – weren’t able to ask questions for time restraints, I’d encourage you to call Jim Dean and we can get those questions answered. But lastly, I’d like to thank you for your support. As we said, we’ll get back to you in the December/January timeframe about our revised CapEx and production guidance. Even though – and I’m going to say it again, even though we’re rethinking our CapEx program for next year, again I want to reinforce that we have a very high quality Eagle Ford asset and our sole intent is to maximize the returns on the money invested. And under this pricing environment, which maybe deteriorating further, we feel that retaining a strong balance sheet is very, very important to a company like Penn Virginia at this time. So I’d like to say goodbye and have a great day. Thank you very much.

[Operator:]

Ladies and gentlemen, thank you for your participation in today’s conference. This concludes the program. You may now disconnect. Everyone have a great day.