Penn Virginia Corporation
Q2 2015 Earnings Call Transcript

Published: 30 Jul 2015

[Operator:]

Good day, ladies and gentlemen, and welcome to the Penn Virginia Corporation Second Quarter 2015 Earnings Conference 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. As a reminder, this call maybe recorded. I would now like to introduce your host for today's conference, Mr. Edward Cloues, Chairman of the Board. Please go ahead, sir.

[Edward B. Cloues:]

Kristie, thank you very much. As you said, my name is Ed Cloues, I'm the Chairman of the Board. I'm not usually doing this. But I would like to thank you for joining us today for our second quarter 2015 conference call. I'm joined today by members of our management team, who include Baird Whitehead, our Chief Executive Officer; 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 with the meeting, I'd like to remind you of the language in our forward-looking statements section of the press releases, as well as the Form 10-Q, both of which were filed last night. I'm leading off today's call. I'm not usually on these calls to review three items with you before we get to the normal operations reports that you're accustomed to hearing. First item I'd like you to address and, as you know, Baird Whitehead has informed the Board of Directors that he would like to retire as soon as we can identify and bring on board his successor. I'd like to make several points about this. First, this was Baird's decision for personal reasons and the succession process is a very amicable one. Baird has agreed to stay on and be fully engaged in the business until a new CEO is identified and brought on board. The Board has a Search Committee that's actively underway with SpencerStuart to fill this spot, obviously the critical spot in the company. In the meantime, there should be no question that Baird will be fully committed to PVA and has the full support of the Board. Second point I would like to address involves a variety of rumors that have been in the marketplace over the past several months. We do not, as a matter of policy, normally comment on market rumors, but I will confirm that earlier this year the company did run a sale process with a major investment bank, but received no credible bids. We did not reject any offers as some have suggested. In fact while there was a reasonable level of interest, at the end of the day, there were no offers to consider. The difficult environment for oil prices just caused a lot of people to be very hesitant, so that we wanted to get on record with this now to clear up any confusion that might exist in the marketplace. And the third point I would like to make is to emphasize that the Board regularly considers strategic alternatives that maybe available to the company. In this regard, we are ready to speak with any credible party that may have a good idea for us to evaluate. As we look for these ideas, however, we are intensely focused on reducing costs, raising capital and doing whatever may be required to ensure that we have enough liquidity to operate through the end of 2016 and beyond whatever the price of oil may be. We can't control oil prices. We can't control demand. We can't control the global economy. We can control what we spend and where we drill and it's something that is a focus daily of everything that we're doing. With these introductory remarks, I'll turn the call over to Baird Whitehead, our CEO, for our operations report. Baird?

[H. Baird Whitehead:]

Appreciate it, Ed. Thank you very much. As was the case in the last two quarters, we are using a slide presentation, which is out there on our website that we will go through simultaneously as part of the presentation. If you look at slide two, we did have some significant accomplishments during the second quarter, some of which I would like to highlight. First off, we think we had a good quarter financially, exceeding our guidance and most Street estimates as it relates to revenues and cash flows. Secondly, the 25% well cost reduction we reported in the previous call has improved further, with average well cost now down 42% from the third quarter of 2014 and down 30% from the fourth quarter of 2014. These cost savings are primarily on the completion side but also we've had some significant reductions on the drilling side that John will get into in a little bit more detail. Considering we have drilled our recent two-string wells at an average $5.3 million cost, we think we can take off an additional $400,000 to $800,000 per well from the assumptions we have used to build our guidance for the remainder of 2015 and 2016. We have taken our 2015 CapEx guidance towards the lower end of the previously provided guidance with a $325 million to $345 million plan now in place for 2015, which implies only about $45 million to $50 million of CapEx per quarter in the second half of this year versus $65 million to $70 million per quarter of adjusted EBITDAX. Pro forma, the sale of our East Texas assets, we have sufficient liquidity now and anticipate at the end of the year to execute upon not only this year's remaining program but also going into 2016. We also have other options at hand to supplement our liquidity in 2016, including the additional sale of non-strategic assets or potential JVs and, of course, we're always going to keep our eye on oil prices. I can assure you we are going to do everything we can to support our liquidity situation in order to remain financially healthy into 2016. Very preliminarily, we are estimating to spend $200 million to $250 million in 2016, assuming a WTI oil price of $55 to $60 per barrel, which would result in an exit rate for the fourth quarter of 2016 up approximately 10% from the mid-point of production guidance for the fourth quarter of 2015. While production was lower than expected during the second quarter, we have grown significantly year-over-year. The issues that caused our production variance in the second quarter we think have been addressed going forward and includes a focus on drilling only lower Eagle Ford wells in Gonzales County specifically where our drilling and completion costs are lower and our economic returns are optimized. We are also going to adjust our completion design, which ultimately we think could improve the early time performance of both the upper and lower Eagle Ford. We think the upper Eagle Ford in spite the problems we had this past quarter remains a viable play for us. To some extent the lower IP rates can be possibly explained with lower volumes of sand being pumped over the last two quarters. I want to remind everybody, we still don't have a lot of upper Eagle Ford data. We only have 33 wells we have drilled and completed to-date in this play. We're also going to resume drilling more complex staggered upper and lower wells from the same pad during early 2016 to support the theory that potential improvements in frac complexity with the staggered upper and lower patterns can potentially improve upon both the lower and upper results. The staggered alternating pattern can possibly explain the excellent results we have seen to-date on the RBK 1 through 4 wells, and John Brooks will get into a little bit more detail concerning this in a few minutes. On the other hand, the lower Eagle Ford results are consistent with expectations and in the immediate future, we'll be focusing on these type of completions primarily in the oilier and less expensive areas of Gonzales and northwestern Lavaca County. On slide three, as we mentioned we had a good financial quarter with revenues, including hedges, cost and cash flows which were better than expected. As you can see, we had an excellent and mostly consistent lower Eagle Ford results over the past 12 months and we've been able to drive these costs down for the wells over the last three quarters in order to support what we consider good returns at these lower product prices. Also based on the results of an offset operator, we are going to transition to pumping slickwater fracs in the second half of this year. There is solid evidence that not using gel fluids and pumping up to 500,000 pounds per stage or 1,600 pounds to 2,000 pounds per lateral foot will improve the early time performance of these wells up to 15% over and above the type curve we have utilized in the past. We have also engaged a third-party frac consultant that has helped us in the design of these slickwater fracs. We expect in spite of the increase in completion costs that there will be a net economic benefit due to the higher initial and short-term production rates. Slide four and looking ahead to 2016, as I previously stated, our number one goal as we exit this year going into 2016 is to preserve healthy levels of financial liquidity and remain within any current or renegotiated leverage covenants by focusing on a program with the highest return wells and CapEx size that optimizes this liquidity. In addition, we will take any necessary step to improve liquidity, including further non-strategic asset sales or potentially forming a JV in the Eagle Ford. We've had some very preliminary discussions with some of our banks that feel that our Eagle Ford assets could be conducive for a joint venture on a promoted basis either with a drill and carry or receiving some proceeds upfront. We are in the earlier stages of analyzing this option. Right now, the 2016 program size is estimated to $200 million to $250 million with a 2016 fourth quarter production exit rate that is consistent with or up to 10% greater than what is expected in the midpoint of our fourth quarter 2015 guidance. But the size of the program, of course, is subject to change and, as I said earlier, we're going to keep our eye on product pricing and liquidity. The program for the second half of the year in 2016 will focus our spending on our lower cost, higher return, lower Eagle Ford two-string wells primarily in Gonzales County, which are expected to generate at least 20% rate of return or higher if prices improve or further improvements in reducing drilling and completion costs can be made from what has been assumed in building our guidance. If we could reduce our cost by only $400,000 which had a minimal we think we can do, our return could increase by 3 percentage points to 4 percentage points. And with that, I would like to turn it over to John Brooks to give you some more detail on the operation side.

[John A. Brooks:]

Thanks, Baird. I'm going to flip over to page six, which starts the second quarter operation summary. We've maintained our significant core land position of approximately 103,000 net acres. That provides an ample drilling inventory in the Eagle Ford, the highly contiguous nature of which also gives us operational advantages relating to gathering of the oil, gas and flow back and produce water as evidenced by our ongoing reduction and unit operating cost of $5.10 per BOE in the second quarter. We've grown our total Eagle Ford production by 30% over the last 12 months. Company-wide pro forma total production grew 23% over the last 12 months. And for the full year 2015 production should be flat versus 2014 but growing 15% to 26% pro forma for divested assets. Our recent lower Eagle Ford results are in line with expectations, but several recent upper Eagle Ford wells have performed below expectations. We've identified three factors that we're focusing on that we think can improve the upper Eagle Ford performance. First, pumping in more profit and, secondly, in conjunction with that transitioning the slickwater fracs from hybrid fracs and, thirdly and perhaps more importantly is staggered offset lateral placement as we configured our RBK pad. As you may recall from the last quarter's call, our RBK pad consist of four wells with the staggered offset lateral placement in both the upper and lower Eagle Ford with the laterals nominally 400 feet apart in plan view and the stimulation designed around 250 foot stages targeting 300,000 pounds of proppant per stage or approximately 1,200 pounds of proppant per lateral foot. Anecdotally, Marathon has tested a similar well bore configuration, they call it stack and frac, and they had a lateral in the Austin Chalk. But our RBK pad has been producing for less than four months and has now produced over 292 MBOE, validating our approach of using tighter lateral spacing to achieve a greater stimulated rock volume or improved fracture complexity and generating excellent well performance even with a conservative choke management protocol in place. In the absence of a four well pad figured with staggered offset laterals as in the RBK pad, however, we hope to achieve this inferred increased fractured complexity and enhanced production are transitioning to the slickwater and higher profit intensity. Current plans are to target 1,600 to 2,000 pounds of proppant per lateral foot from our current 1,200 pounds with slickwater instead of the hybrid fracs we've been pumping. This should significantly reduce chemical cost while pumping a thinner, less viscous fluid although water and proppant volumes will increase. Based on our observations of similarly treated wells in the vicinity of our acreage, the data indicates an uplift of early time production that can further enhance economics. The effect of higher profit volumes with slickwater on the longer term production in EUR cannot be yet quantified, but the early time productions acceleration at a minimum appears to justify this approach. The economic benefit includes an approximate 15% production uplift in the first year. While we have discontinued drilling three string wells and upper Eagle Ford wells for the time being, we do plan to replicate the RBK pad with a similarly configured pad in 2016's drilling schedule and hopefully even further enhance the outcome with the aforementioned higher intensity profit loading and slickwater. Total well cost continue to decline falling by 42% since third quarter of 2014 and over that time period, drilling cost have decreased by 30%, completion costs have declined by 51%. Our operations continue to execute efficiently at a high success rate across our asset base with drilling efficiency continuing to increase as we've averaged at 1,060 feet per day for 2015 through the first week of July, which is an 18% improvement over 2014. For completions in the second quarter, we pumped 433 stages with 100% success rate with plug-n-perf operations and coiled tubing drill out. And our operations team has executed this high level now for three consecutive quarters. As you can see from the charts on slide seven, we continue to make significant progress in reducing well cost and operating expenses. Since February of this year, our two-string well costs averaged approximately $6 million. Since March of this year, our three-string well costs averaged approximately $8.1 million. However, we have discontinued drilling three-string wells for the time being. During the second quarter, we completed and turned to sales 16 Eagle Ford wells. Of these 16 wells, nine were completed in the Upper Eagle Ford, which we have also discontinued for the time being. The bottom graph on slide seven shows our trend of improving cash operating cost per BOE over the last four quarters. We continue to improve these cost reductions which were $5.10 per BOE in the second quarter, representing a 28% reduction from 3Q 2014, 13% reduction from the fourth quarter of 2014, and an additional 2% drop from the first quarter. Slide eight shows our anticipated well economics for the second half of 2015 incorporating the cost and assume production benefit of increased profit loading as I've previously mentioned even though this production benefit has not been included in our guidance. While we think initially our cost could be higher as we transition away from hybrid fracs to slickwater fracs, as we get further along the learning curve, we anticipate those costs will ultimately decline back to near where current costs are. The next two pages summarize IP data for our most recent Upper and Lower Eagle Ford wells, both of which continue to perform well across our acreage position with a handful of exceptions, mainly in the Upper Eagle Ford. At this time, I'll turn it over to CFO, Steve Hartman, for the final financial portion of the call.

[Steven A. Hartman:]

Okay. Thanks, John. I'll start with an update to our 2015 guidance. As Baird mentioned, we are decreasing our capital expenditures guidance to a range of $325 million to $345 million. We've spent $241 million as of the end of the second quarter, so our guidance for the second half of the year is $84 million to $104 million. We expect the third quarter will be more active than the fourth. Our guidance for the third quarter is $52 million to $61 million and then we expect a slowdown further with fourth quarter guidance being $32 million to $43 million. We should be turning in line approximately 16 gross wells, 13 net wells in the second half of the year. Drilling and completion capital for the second half of the year is expected to be $83 million to $98 million. We are lowering our production guidance for 2015 to a range of 75.65 to 82.65 MBOE. This includes an adjustment for the sale of our East Texas assets for the last four months of the year. It also takes into account less rig activity for the second half of the year and more development emphasize in Gonzales County. Keep in mind, our locations in Gonzales County; specifically Peach Creek and Rock Creek are the cheapest to drill and have the highest rates of return in this price environment. The trade off for this development plan with no Lavaca County wells as we would expect lower total production for the year, because of the lower GOR and lower IP rates, but with better rates of return and lower cost. Also this plan does not assume any of the potential performance improvements that Baird mentioned from changing the frac design. We are using the same type curve as before, so there is potentially some upside to new design works as anticipated. We expect third quarter production will be approximately 18,500 to 22,800 BOE per day. So far in July, our production has averaged just under 22,000 BOE per day, so we are on track. Oil production should be about two-third of total production or 12,200 to 15,000 barrels of oil per day for the quarter. We expect fourth quarter will decline with the reduction in rig count and we will end the year at 16,300 to 19,600 BOE per day. Oil production should be approximately 11,100 to 13,600 barrels of oil per day for the fourth quarter. We are lowering our operating cost guidance for the year based on lower experience cost in the first half of the year and lower volume expectations. We are raising our company DD&A rate slightly to reflect the sale of the East Texas assets. However, the depletion rate in Eagle Ford is coming down as we bring on lower cost wells. Adjusted EBITDAX is expected to be $285 million to $310 million based on an assumed WTI oil price of $55 for the second half of the year. We lowered our price assumption by $4 per barrel since the May earnings call. We expect the credit facility will be drawn in the range of $172 million to $192 million at the end of the year. This is pro forma for the East Texas sale, which is expected to close in the third quarter. We expect a $30 million adjustment to the borrowing base for the sale, which would give us an adjusted borrowing base of $395 million at closing. Given that we would expect to exit 2015 with liquidity of approximately $200 million to $220 million before any borrowing base reductions in the fall and leverage of around 4.3 times. It's too early to know exactly what will happen in the fall re-determination in October, but I expect it will come down. In any case, even considering the fall borrowing base reduction, we expect we'll have sufficient liquidity to complete this year's program and get us into 2016. Moving on to 2016, we want to give you some early preliminary directional guidance on what we're thinking. Our goal, as Baird mentioned, is to preserve liquidity, while keeping our production exit rates relatively flat year-over-year. To accomplish this, we would expect to invest $200 million to $250 million in 2016. This would fund about 26 to 28 net wells and would keep our production flat to perhaps growing up to 10% of a growth rate exiting 2016. We think that this is an optimal program for maintaining production and managing cash flow while still balancing leverage and liquidity needs. This plan assumes $55 to $60 oil in 2016. If these prices persist into 2016, we could exceed our total debt leverage covenant a year from now and we are being proactive on this, and I'm already talking with our agent bank about relaxing or eliminating the covenant. Moving on to the next slide, I'll review our hedges. We have 11,000 barrels per day of oil hedged for the remainder of 2015 at a weighted average price of $89.86. Using the midpoint of guidance, we have 84% of our oil hedged. The quarterly ranges are shown on the slide. There are lower puts sold at $70 on 5,000 barrels per day in the second half of the year. For 2016, we have 6,000 barrels per day hedged at a weighted average price of $80.41. There are no lower puts sold on 2016 volume. We haven't provided volume guidance for 2016, but this is roughly about 45% of our oil volume hedged at this point. And finally, you can see the hedges are doing their job. And our assumed WTI price for full year 2015, which includes actual pricing for the first half and our assumed $55 price for the second half, we would receive $124 million to $130 million of hedge proceeds for the year, and $57 million of that would be received in the second half. That concludes the financial slides, Baird.

[H. Baird Whitehead:]

All right. Thanks, Steve. I just want to point out there was one slight mistake on slide two. The CapEx is actually $200 million to $250 million, it's a typo. So, we had it as $200 million to $250 million on the other slide which was correct. The $200 million to $225 million is not correct. So just wanted to point that out. And with that, Kristie, we're ready go ahead and take any questions.

[Operator:]

Thank you. And our first question comes from the line of Neal Dingmann of SunTrust. Your line is open.

[Neal D. Dingmann:]

Good morning, guys. Baird, I guess, the first question for you or Ed, I'm just wondering – based on Ed's comments about strategic alternatives, it looks like the focus listening to you and John is at least for the near-term – and I agree, it should be on the Lower Eagle Ford there up in the North. Your thoughts on the strategic alternative, would that include potentially selling some acreage. You guys obviously are asset heavy. Again, you could probably break off a piece and still be more than ample there, your thoughts on, Baird, just strategic alternatives what that could include?

[H. Baird Whitehead:]

At this point in time, I think, as I mentioned, Neal, we have very early talked to some banks about soliciting some level of interest from some parties who may be interested on a drill to earn kind of basis on a promoted basis whereas they would either put some money upfront or they would participate with some kind of drill and carry whereas they would disproportionately pay some of the drilling cost. So, you're right, we've got plenty of acreage and a depressed oil price environment. It makes sense for us to try to accelerate activity by having a viable partner and get some of the remaining acreage tested because we do have a chunk of our acreage that we still think is very prospective, especially in the upper that we picked up here, I guess, it was a year or two ago. So, yeah, it's something that we are actively pursuing and looking at, at this time.

[Neal D. Dingmann:]

Okay, makes sense. And then, just two more quick ones. Baird, on that guidance you were just talking about, the CapEx guidance. Just walk me through and I know on that – you said the $200 million to $250 million and you thought based on kind of what the rig activity would be. I think you're thinking about 10% higher than that fourth quarter. Is that based on just wells still left to be completed or is that just based on a second rig coming? Again, what gives you and John the confidence that you can have that higher production next year versus the fourth quarter given the lower spending next year?

[H. Baird Whitehead:]

Yeah. We've actually ratcheted down spending as we speak. In fact, we're down to one rig. We just let – we had two rigs, we've let one of those two go. We're down to one. Our fourth quarter – or our 2016 plan tentatively includes going back up to two early in the year and then going back down to one as the year progresses. So, the production profile, it reflects, we would actually bottom out in production on a quarterly basis fourth quarter this year into first quarter of 2016. After which because we bring a second rig back early next year, production would ramp back up as the year progresses. So that's sort of the indication of how we expect production to be. And of course, we could, if we find a JV partner, we decide to ratchet things back up. Of course, it might – it would be probably a reduced working interest. It's undefined and undecided at this time, of course. But in order to stay focused on liquidity that's how we've preliminarily have budgeted for rigs.

[Neal D. Dingmann:]

Got it. And then just lastly, Baird for you or Steve, just -Steve, you mentioned about maybe some of those covenant easements. Would there be any cost behind that or just as you have some – I know, it's very preliminary with some of the banks, anything to consider on that side if we were to see that?

[H. Baird Whitehead:]

Did you say cost, Neal?

[Neal D. Dingmann:]

Yeah. To obviously have some of those restrictions or some of those covenants change or...?

[John A. Brooks:]

I expect there'd be an amendment fee to that and probably in the range of 10 to 20 basis points would be my guess.

[Neal D. Dingmann:]

Okay. But nothing more than that?

[John A. Brooks:]

No, no, a minor fee.

[Neal D. Dingmann:]

Got it .Got it. Okay. Thank you all.

[H. Baird Whitehead:]

All right. Thanks, Neal.

[Operator:]

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

[Stephen F. Berman:]

Good morning, everyone. Good morning. A clarification – I'm looking at slide eight, the $6.9 million well cost for the two-string lower Eagle Ford wells and tying that back to the recent ones at $5.3 million, is the difference just from the bigger proppant levels and doing slickwater. I'm just trying to get that cleared up.

[John A. Brooks:]

Yeah. That's primarily it. It's a little bit more money involved with the slickwater fracs, and that's normalized to a 23 stage well and the other wells earlier in the year were 21 stages. So we normalized it to 23 and then used the higher intensity proppant with frac water to come up with the $6.9 million, but we think we can drive that down after we get on the learning curve a little bit.

[Stephen F. Berman:]

And how quickly do you think you can knock that $400,000 to $800,000 off of that $6.9 million?

[John A. Brooks:]

Well, we would hope to do it here in the third quarter. The primary issue is pumping a lot more volume of both sand and fluid. And if we can get the higher density fluids in there, what we've seen on the hybrid fracs than those costs come down a lot quicker.

[H. Baird Whitehead:]

And just to say one thing, Steve, to add on what John said. This $5.3 million we spent on some of the recent two-string wells, they were AFE'd around a $6 million, $6.1 million. So we actually reduced. It was actually a lot less than what our expectations were. So if you take the $5.3 million and add money back in for a larger frac in a larger slickwater frac, you probably would get back up into the $6.4 million range way off of that if we can do what we did, like in the Kudu wells, for instance. So, it's something we think we can achieve fairly quickly, but just for planning purposes we assumed higher costs at this point in time. But we think we have a good chance to get it down pretty quick.

[Stephen F. Berman:]

Understood. Thanks. And one more, the average 30-day rate for the second quarter wells was just under $600,000 was lower than what you've been experiencing, is that mainly because of the issues you talked about, can you elaborate on that number a little bit?

[John A. Brooks:]

Yeah. The upper Eagle Ford results really dragged down those IPs. That was the biggest culprit in driving those down. And plus we had a couple of wells, like I mentioned earlier that rolling 21 stages, so those came in at slightly less as well. But the lower Eagle Ford wells, all in all performed in line with the expectations, but overall results were dragged down by the upper Eagle Ford.

[H. Baird Whitehead:]

Yeah. And one of the thing just to elaborate further, as we have stated in the past, our upper Eagle Ford has really a different decline profile than the lower. And yet your IP in 30-day rigs on the upper were below our expectations. We expect to see and have seen some lower levels of decline as we have seen even when we had the higher IP in 30-day rigs. So it's consistent – the type curve profile in these upper Eagle Ford wells, it appear to be consistent. We've not seen some precipitous decline in the upper just because it had a lower IP. So I just wanted to add that.

[Stephen F. Berman:]

All right. Thanks, guys.

[H. Baird Whitehead:]

All right. Thanks, Steve.

[Operator:]

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

[Brian M. Corales:]

Hey, guys. Just on the upper Eagle Ford, it looks like the early results were much better. Did you all actually reduce the sand or are you just planning to increase it from where you were before?

[H. Baird Whitehead:]

Well, we've reduced the sand, Brian, in the last couple of quarters, the first and second quarters specifically from late last year. We had some indications at that time. We had actually achieved a flattening whereas the benefit versus amount of sand pumped per stage was sort of leveling out. So that's why we reduced it. After looking further and getting more data and taking this recent data where these lower sand volumes, it's become more clear with a positive correlation that we should be pumping more sand. And I think this is important even though it doesn't exactly deal with your question you just asked. The RBK wells is in and around some of these upper Eagle Ford disappointing wells we drilled. So I think there is something to not only pumping more sand as we have historical numbers that show that we should be doing that, but also they are staggered in alternating pattern of upper and lower. Even if you pump less sand as we did on the two upper RBK wells this staggered pattern and closer spacing and probably better frac complexity actually seems to make up for lesser sand pumped if all that makes sense. So there is a couple of things going on from the theoretical and technical standpoint that we need to get our arms around over time and we will test this stagger and patter again in 2016. But we think at a minimum we should be pumping more sand and we should see the same benefit by pumping more sand even on the lower wells. So I hope that answers your question.

[Brian M. Corales:]

No, that was very helpful. And then kind of a follow on to Neal's question earlier. I mean, obviously Eagle Ford JV could be makes sense. Is there other things that could be monetized since you're looking to monetize out there that could be bring in some additional liquidity?

[H. Baird Whitehead:]

Steve, why don't you go ahead and take that if you don't mind?

[Steven A. Hartman:]

Yeah, Brian. There are some non-core assets that we can sell. We have some assets that are not part of the contiguous block that we've been looking at trying to monetize. We feel very confident that that will happen. There is also the water system that's still out there. We're still evaluating that. I don't think we're going to have that done in 2015, but in 2016 that could be an asset that we could use to plug any gap for that program. And then plus, there is always just – looking at our contiguous block and maybe looking at that. Granite Wash of course is still out there, so yeah, there are some non-core assets that we could still look at monetizing and we are.

[Brian M. Corales:]

All right, guys. Thank you.

[H. Baird Whitehead:]

All right. Thanks, Brian.

[Operator:]

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

[Richard M. Tullis:]

Thanks, good morning. Baird or John, just going back to the latest upper Eagle Ford results, in your opinion what percentage of, say, that 50% decline in 30-day rig could be attributed to the reduced prop and for lateral stage?

[H. Baird Whitehead:]

Why don't you give a stab at it, John?

[John A. Brooks:]

Well, I think it's going to depend on where in the assets you are. In the northern part of our acreage up in Peach Creek, we drill some wells, say, two new wells, two of those three were moral wells and they were in a low GOR environment. They were very, very cheap to drill and they came in at some reduced rates, and that's probably irrespective of a sand loading issue as much as a rock issue and being in a lower pressure environment. So I would say, the less sand goes hand in hand with the completion configuration, as Baird mentioned, being in the staggered offset lateral placement is critical. You can probably pump less sand in that environment than you could in just a one or two well pairing. So I have a difficult time attributing a percentage of the underperformance to the lack of sand, but it's probably 25% or something of that nature.

[Richard M. Tullis:]

Okay.

[Steven A. Hartman:]

You have to remember, we continue – even though we felt that we had to de-risk our upper across the majority of our acreage, the bulk of the program, the second quarter program in late first quarter was sort of an western Lavaca County acreage. And as John said, it has a different characteristic that being lower gas content which of course does affect the early time rates, especially early time rates on the lower. So – to some extent, caught it by surprise at this point we don't see any geological differences, rock differences from the eastern part of our acreage where we have drilled good wells and they continue to be good wells versus the western part. The only reason, the only two variables that are changing is the GOR and the amount of sand that we pump. So we have to hone in on those two variables and take those into account going forward.

[Richard M. Tullis:]

Okay, that is helpful. Thank you. Baird, I know you mentioned that you expect a shallower decline from these 2Q wells in the upper Eagle Ford. At this point, what do you think the average EUR per well is for that group of wells?

[H. Baird Whitehead:]

I'm hesitant to say anything at this time, Richard, because we don't have a lot of production information. So it's probably a question and these to be deferred probably the next quarter when we have more production information, we'll give you better answer.

[Richard M. Tullis:]

No that's fine. If you look at your roughly 100,000 acres in the Eagle Ford, given what you've seen in the second quarter and then the plans going forward next year for the upper Eagle Ford, what percentage of the acreage do you think is economic, using the expected well cost with the new completion method and say using $60 oil?

[H. Baird Whitehead:]

Well, we think – we have some acres and we have yet to test. We have roughly 11,000 acres, we picked up a year or so ago that we need to get some wells drilled on, I will put in the, I guess, delicate kind of area at this time. We still think almost all of our acres is economic. In fact, we could be drilling three string wells that assuming this 15% uplift because slickwater fracs still show positive returns and adequate returns. The reason we backed off on the three string wells is it has a certain amount of operational – additional operational risk because of the execution side, because of the pressure environment that you're in and also trying to get those kind of wells fracked because your frac pressures are higher, your frac ratings tend to be somewhat higher than what we have over and the shallow report. It just introduces another risk that we don't want to take at this time. But we still think that the returns are still adequate even at today's $55 to $60 oil price. We decided to back off for CapEx reasons and return reasons at this time.

[Richard M. Tullis:]

Okay. And then, just lastly for me. How many net Eagle Ford wells would you expect to drill next year, say, in a $200 million to $250 million budget?

[H. Baird Whitehead:]

I didn't hear the question. How many – what...

[Richard M. Tullis:]

How many net Eagle Ford wells would you expect to drill next year based on the preliminary budget?

[H. Baird Whitehead:]

26 to 28 net wells.

[Richard M. Tullis:]

Okay. That's helpful. All right. Thanks a bunch. I appreciate it.

[H. Baird Whitehead:]

Okay, Rich. Thanks.

[Operator:]

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

[Sean Sneeden:]

Good morning. Thank you for taking the questions.

[H. Baird Whitehead:]

No problem.

[Sean Sneeden:]

Steve, maybe to start off with you thinking about 2016 guidance here. It seems as though the midpoint of guidance and using the price deck you guys have suggested, the funding gap for next year roughly $100 million is that generally how you're thinking about it?

[Steven A. Hartman:]

Yes, I was thinking $100 million to $125 million. So yeah, I think that's right on top of what we're thinking.

[Sean Sneeden:]

Okay. And then as you kind of think about your exit for 2016 and lean into 2017, if we're still in the current price environment, you kind of touched upon this a little bit earlier but what are your thoughts on liquidity as you exit 2016...?

[Steven A. Hartman:]

When we exit 2016, I don't think we're ready to give that kind of guidance yet. We're focused on 2015. We're focused on giving you directional guidance for 2016 on a capital program and we just talked about funding gaps, so funding but there's just a lot of time between now and then. I don't think we want to comment on that.

[Sean Sneeden:]

Sure. And then maybe just kind of thinking about some of your comments generally on liquidity, it seems as though it's mainly focused on JVs or asset sales. At what point does doing capital raise – say the form's like a second-lien financing – at what point does that make sense or how does that kind of stack up against just general asset sale plans in that sense?

[Steven A. Hartman:]

Well, it's definitely one of the options that we have, and we've considered that along with everything else. The markets are pretty tough right now across the board. So I'd say that we're not looking at something right this minute, but it is something that we are going to be looking at and it's one of the options that we can look at. And markets improve, then we'll look at that at that time.

[Sean Sneeden:]

Okay. And then, maybe just on G&A, the kind of the $5 a barrel guidance, it just appears kind of relatively high compared to overall level of production and general size of the company. As we go along into 2016, is there any room to drive that lower from kind of the, call it, $40 million a year run rate you're on?

[Steven A. Hartman:]

Yeah. Certainly is. I mean, it's something we'll continue to look at – especially, this kind of rig activity is something we'll keep our eye on. But if we stay in this kind of depressed environment, it's something we'll have to take a closer look at, no question.

[Sean Sneeden:]

Okay. And then maybe, Baird, for you, just kind of lastly, when you think about an Eagle Ford JV concept, would you consider doing just a JV in the Upper Eagle Ford to kind of help derisk that and take some of your own kind of capital off the table or would you – or how would you kind of ideally describe a JV in the play?

[H. Baird Whitehead:]

I think you have to include both lower and higher risk kind of wells. And I certainly think one way for us to get our Upper Eagle Ford tested associated with this 11,000 acres we picked up here a year or so ago would certainly be included in one or two of those wells within that overall package with a JV partner. So, to answer your question, that's the beauty of trying to do one of these things. You can try to get some of this stuff tested. Also, give that party some upside associated with that testing, if it does work out, in fact. But it's something that will be definitely in the cards.

[Sean Sneeden:]

Okay. That's helpful. Thank you.

[H. Baird Whitehead:]

All right. Thank you very much.

[Operator:]

And our next question comes from the line of Kim Pacanovsky of Imperial Capital. Your line is open.

[Kim M. Pacanovsky:]

Yeah. Hey, good morning, everyone. So I'm just – in your last presentation, you said that the Upper Eagle Ford spending was largely completed. So I'm just trying to correlate the drop in the mid-point of guidance, which is over 3,000 BOE a day to the old well count per area to the new well count per area because it didn't look like you had a lot of Upper Eagle Ford left to do anyway?

[H. Baird Whitehead:]

Well, there is a couple of things going on. I mean, because the second quarter Upper Eagle Ford program was disappointing, that variance that hit us in the second quarter runs throughout the remainder of the year. And that's a fairly sizable amount of the overall variance. The other thing that's going on is the program for the remainder of this year going into 2016, that being Lower Eagle Ford wells up in Gonzales County has a different type curve associated with it; i.e., lesser IP, lesser 30-day rate, but also has of course, much lesser drilling and completion costs associated with it. And these are not very gassy kind of wells also, which adds to the equivalent production so those two facets in combination are causing the variance.

[Kim M. Pacanovsky:]

Okay. So in the old CapEx, what were you planning on doing in the second half in the Upper Eagle Ford that's now shelved?

[H. Baird Whitehead:]

We had a few wells.

[John A. Brooks:]

Yeah, I think we had some left. I can't remember that answer, Kim.

[Kim M. Pacanovsky:]

Okay.

[John A. Brooks:]

I don't have everything handy.

[Kim M. Pacanovsky:]

Okay. And then of the 10 Upper Eagle Ford wells that you reported that had the disappointing results, were all of them fracked with the lower sand concentration?

[John A. Brooks:]

Yes.

[Kim M. Pacanovsky:]

And then for the Lower Eagle Ford, besides the RBK, how many wells in the quarter also had that lower sand concentration and was the RBK the only one that had the staggered configuration?

[John A. Brooks:]

Yes, of that complexity with four wells. I mean we had some two well pads upper and lower, but the four well pad RBK, that was the only one we had in that situation.

[Kim M. Pacanovsky:]

Okay. And then one last question, I think Steve or somebody referred to the differential on the well cost now with the change to slickwater and more proppant, can you just separate out those two items for how they are additive to the well costs, the change in fluids and the increase in proppant back up to 400,000-pound or greater per stage?

[John A. Brooks:]

I can't give you exact breakdowns. But when you run a slickwater kind of frac job, there's two things going on. You can't run your sand concentrations are a lot less than what they may be on the gel frac situation. So you have to in order to get not only more sand away, even if you ran the same size job, say a 300,000-pound kind of frac stage, it would take more water in order to get that done because your concentrations are less. So, if you increase to 500,000, there's a disproportionate amount of water required not only because you increase the sand but because you have no viscosity associated with this water. So you're pumping essentially as a high rate as you can in order to put it away. So that's what causes the variance in cost.

[Kim M. Pacanovsky:]

Okay, great. That's all I had guys.

[John A. Brooks:]

Okay. Thanks, Kim.

[Operator:]

Our next question comes from the line of Adam Leight of RBC Capital Markets. Your line is open.

[Adam Leight:]

Hi, good morning everybody. I think most of my questions were answered. Just a couple follow-ups. On the CapEx number for next year, can you – is that the total CapEx or is that just join and completion and if you can breakout some ballpark on proportionate?

[John A. Brooks:]

Yeah, that's total CapEx, Adam. Other CapEx is not related to drilling and completion, it's right around $17 million give or take a few million.

[Adam Leight:]

Can you just remind me also what your average working interest in Gonzales is?

[H. Baird Whitehead:]

I don't have the exact number but gross of net wells, it's a high working interest assumption we have. We've also seen, some of our partners have been going non consent on us up in that area, so that increases our working interest, so it's high.

[Adam Leight:]

Great. Thanks. Steve, if you're talking to your bank group about covenant relief, would you anticipate that you would get some kind of determination – bad use of words – around for you – redetermination of your borrowing base, or do you think you get some earlier sense of ability to figure out what that's going to be?

[Steven A. Hartman:]

I'm not sure if it's going to be the fall redetermination around the East Texas sale. It's going to be somewhere in their tied with some other activity with the banks.

[Adam Leight:]

Okay, great. Thanks.

[John A. Brooks:]

Okay. Thank you, Adam.

[Operator:]

Our next question comes from the line of Robert DuBoff of Oppenheimer. Your line is open.

[Robert DuBoff:]

Hi. Good morning, everyone.

[H. Baird Whitehead:]

Good morning.

[Robert DuBoff:]

I see that your lease acquisition guidance is actually ticked up a bit. Is that just because you need to lock up more acreage since you're not going to be drilling out east and how much do you think you need to spend next year to lock up all the acreage you want to?

[H. Baird Whitehead:]

Well, I think, going forward our lease acquisition effort is going to be very minimal. The reason it was somewhat elevated in the second quarter, if you say some cleanup stuff we needed to do in order to firm up some drilling units, new drilling units we have put together. But going forward, it's going to be minimal. If we could bring a JV partner in, it may ratchet up somewhat, but it would be utilizing a partner to help us do that some disproportionate level, but acreage acquisition going forward is going to be minimal.

[Robert DuBoff:]

Okay, great.

[H. Baird Whitehead:]

Okay. Thank you.

[Operator:]

Our last question comes from the line of Owen Douglas of Baird. Your line is open.

[Owen Douglas:]

Hi, guys. Thanks for taking my questions. I just wanted to get a little bit of a sense in terms of what happened in the significant decrease in the well cost. Just looking at your two-string well cost from March to May, it looks like there is a big step down there.

[H. Baird Whitehead:]

Go ahead, John.

[John A. Brooks:]

Well, the biggest factor was just spending fewer days on location. Most of those wells we were on and off 13 days or less. So that is the number one factor that drives our cost down. And then across the board we have seen services – cost of services come down. We self-source our drilling mud and the cost of diesel associated with the oil base mud has come down, and then we transition to water based mud in the intermediate part of the hole. So there is a whole host of little things that all add up to that. But the biggest driver is just being on location fewer days and having our rate of penetration ratcheted up 18% over the last year to over 1,060 feet per day.

[Owen Douglas:]

Got you. I see. And that sounds like that's going to be sustainable for the next few quarters at least. Correct?

[John A. Brooks:]

Yes.

[Owen Douglas:]

Okay. And on that non-D&C part of the 2016 guidance, that $17 million, can you give me a sense for how much sort of think about that number on a go-forward basis as you guys go by developing this highly contiguous acreage position you have. Should I think that a lot of that sort of infrastructure spend is behind you guys or should I be thinking about there continue to be pockets of capital that need to be deployed?

[John A. Brooks:]

It's minimal. We have about $7 million assumed for next year for facility cost which would include some line hook-ups and supporting the water system, but it's minimal. The vast majority of the costs are behind us.

[Owen Douglas:]

Okay. I see. And as far as that well system – sorry, the water system and monetizing that asset, can you give me a sense for ways you can think about doing it? Are there parties that you guys have had discussions with who are willing to buy a portion, or need to be an entire asset sale, can you just provide a little color around that?

[H. Baird Whitehead:]

We talked with same boutique M&A offset. They had helped us monetize the gas gathering system and the crude oil gathering system, sales earlier. We're not pursuing it right this minute. We're not speaking to anyone right now. But at some point, it's probably an asset that would make sense to be in the hands of an MLPE or some other owner, but not right now.

[Owen Douglas:]

Okay. And currently are you guys the only ones utilizing that asset?

[H. Baird Whitehead:]

Yes. We operate it.

[Owen Douglas:]

Okay.

[H. Baird Whitehead:]

We paid the money for it. The water that's being processed is being reused for frac water. We're selling some concentrated brine that comes out of the – the evaporation process is being sold in some cases or being used internally for workout reasons. So it's – timing is everything as far as when you try to sell something like this. Having a size to the system that is large enough and it makes a lot of sense to sell it that time is really the consideration and it will be certainly in a much better situation in 2016 to consider selling one of these currently.

[Owen Douglas:]

Got you. I see. And final question from me, as you think about your current undeveloped acreage at the moment, can you give us a sense for what that drilling inventory is?

[H. Baird Whitehead:]

Well, right now, I don't have an exact number. John, do you remember?

[John A. Brooks:]

I think we've got about 25 or 26 notional units formed in the Cypress Cheyenne south (56

[H. Baird Whitehead:]

That's the undeveloped acreage.

[John A. Brooks:]

...acreage and each one of those units is approximately 640 to 700 acres, so probably on the order of 14,000, 15,000 acres.

[Owen Douglas:]

Okay. I see. All right, guys. Thanks very much.

[John A. Brooks:]

All right. Thank you.

[Operator:]

Thank you. And that concludes the Q&A session for today. I would now like to turn the call over to Mr. Baird Whitehead for any further remarks.

[H. Baird Whitehead:]

All right. Thanks, Kristie. To conclude, we do appreciate you listening in on the call. Even though we hit a bump in the road in the second quarter, we recognize that we think we remain confident in what we're doing both operationally and financially. In this challenging oil price environment we find ourselves in, we're going to do everything we can to continue to drive down our cost, continue to look at our G&A and reduce them further. We got to keep our balance sheet healthy. We all realize what we got to get done and everybody's mindset at this time just to do exactly that. We also realize our declines in equity and bond prices missing it, but ultimately we have confidence in our asset. And with the good asset, which is almost impossible to replicate today, we think we're going to able to re-grow the value of this company. And lastly, as Ed pointed out, I will be retiring. and in all likelihood this is going to be my last conference call until a new CEO is on board. I just want to say thank you for your support throughout the years. I very much enjoyed our discussions and communicating the Penn Virginia story. There's not a lot of people who have the opportunity to be a CEO, and I can honestly say this has been an educational and rewarding experience, and in fact for the confidence the board and the investment community has placed in me. And with that, I'll say thank you and goodbye.

[Operator:]

Ladies and gentlemen, thank you for participating in today's conference. This does conclude today's program. You may all disconnect. Everyone have a wonderful day.