Ranger Oil Corp (ROCC) 2015 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Penn Virginia Corporation second quarter 2015 earnings conference call. (Operator Instructions). I would now like to introduce your host for today's conference Mr. Edward Cloues, Chairman of the Board. Please go ahead, sir.

Christy, 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 am 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, Id like to remind you of the language in our forward-looking statements section of the press release 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 operation reports that you're accustomed to hearing. The first item I would like to address as you know Baird Whitehead has informed the Board of Directors he would like to retire as soon as we can identify and bring on board his successor. I would 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 is actively underway with Spencer Stuart 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 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 may be 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 is something that is a focus daily of everything we are doing.

With these introductory remarks, I will turn the call over to Baird Whitehead, our CEO for our operations report. Baird.

Appreciate it, Ed. Thank you very much. As was the case in the last two quarters we're 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 in most street estimates as it relates to revenues and cash flow. Secondly, the 25% well cost reduction we reported in the previous call has improved further. With average well costs 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 aren't 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 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 also going to keep our eye on oil prices. I can assure you we're going to everything we can to support our liquidity situation in order to remain financially healthy in 2016. Very preliminary we are estimating to spend $200 million to $250 million in 2016 assuming a WTI oil price at $55 to $60 per barrel which would result in an exit rate for the fourth quarter of 2016 up approximately 10% from the midpoint 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 and Gonzales County specifically where our drilling completion costs are lower and our economic returns are optimized. We are also going to adjust our completion design which ultimately we think can improve the early time performance of both the upper and lower Eagle Ford.

We think the upper Eagle Ford in spite of the problems we had this past quarter remains a viable play for us. To some extent the lower IP rates can be explained with lower volumes of sand being pumped over the last two quarters. I want to remind every body 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 earlier 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 RBK1 through four 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. In the immediate future we will be focusing on these type of completions primarily in the (Inaudible) and less expensive areas of Gonzales and north western Lavaca County.

On slide three as we mentioned we had a good financial quarter with revenue including hedges, cost and cash flow 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 have 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're going to transition to pumping slick water 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 1600 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 slick water 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 in looking ahead to 2016 as I've 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 our program with the highest return wells and CapEx size that optimizes this liquidity. In addition we will take any necessary steps to improve liquidity including further non strategic assets sales or potentially forming a JV in the Eagle Ford. We have the some very preliminary discussions with some of our banks who feel that our Eagle Ford assets could be conducive for a joint venture on a promotive basis either with a joint carry or receiving some proceeds upfront. We are in the early stages of analyzing this option.

Right now the 2016 program size is estimated at $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 and 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 a 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 can reduce our costs by only $400,000 which at a minimum we think we can do, our return could increase by three to four 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.

Thanks, Baird. I'm going to flip over to page six, which starts the second quarter operation summary. We have 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 of produced water as evidenced by our ongoing reduction in unit operating cost to $5.10 per BOE in the second quarter. We have 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 full year 2015 production should be that 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 have identified three factors that we're focusing on that we think could improve the upper Eagle Ford performance. First, pumping more (Inaudible) and secondly in conjunction With that, transition to slick water fracs from hybrid fracs. And thirdly and perhaps more importantly is the staggered offset lateral placement as we configured our RBK pad. As you may recall from last quarter's call, our RBK pad consist of four wells with a staggered offset lateral placement in both the upper and lower Eagle Ford with the lateral (Inaudible) 400 feet apart in plan view and the stimulation designed around 250-foot stages targeting 300,000 pounds of proppant per stage or approximately 1200 pounds of proppant per lateral foot. Anecdotally Marathon has tested a similar well bore configuration. They call it stack and frac and they add a lateral in the Austin chalk. But our RBK pad has been producing for less than four months and has now produced over 292MBOE 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 the conservative choke management protocol in place.

In the absences of a four well pad configured with staggered offset lateral as in the RBK pad however we hope to achieve this (Inaudible) fracture complexity and enhance production by transitioning to the slick water and higher proppant intensity. Current plans are to target 1600 to 2,000 pounds of proppant per lateral foot up from our current 1200 pounds with slick water instead of the hybrid fracs we have been pumping. This should significantly reduce chemical costs while pumping a thinner less (Inaudible) 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 in early time production that can further enhance economics. The effect of higher proppant volumes with slick water on longer term production in EUR cannot yet be quantify 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 drilling schedule and hopefully even further enhance the outcome with the aforementioned higher intensity proppant loading and slick water.

Total well cost continue to decline falling by 42% since third quarter of 2014. And over that time period drilling costs have decreased by 30%, completion costs have decline by 51%. Our operations continue to execute efficiently at a high success rate across our assets base with drilling efficiency continuing to increase as we have average 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 have pumped 433 stages with a 100% success rate with plug-n-perf operations and (Inaudible) drill out. And our operations team has executed at 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 costs and operating expenses. Since February of this year our two-string well costs have average approximately $6 million. Since March of this year our three-string well costs have average 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 o2015 incorporating the cost and assumed production of benefit of increased proppant loading as I previously mentioned even those 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 slick water fracs as we get further along the learning curb 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 hand full of exceptions mainly in the upper Eagle Ford. At this time I'll turn it over to CEO, Steve Hartman for the final financial portion of the call.

Okay. Thanks, John. I will start with an update to our 2015 guidance. As Baird mentioned, we are decreasing our capital expenditure guidance to a range of $325 million to $345 million. We have 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 to slow down 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. And drilling and completion capital for the second half of the year is expected to be $83 million to $98 million. We are lower 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 in to account less rig activity for the second half of the year and more development emphasize in Gonzales County. Keep in mind our location 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. A 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 costs. Also this plan does not assume any of the potential performance improvements that Baird mention from changing the frac design.

We are using the same type curve as before so there is potentially some upside if the new designs works as anticipated. We expect third quarter production will be approximately 18,500 BOE 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-thirds of total production or 12,200 barrels of oil per day 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 BOE to 19,600 BOE per day. Oil production should be approximately 11,100 barrels of oil per day 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 experienced 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 the 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 a range of $172 million to $192 million at the end of the year. This is end 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 is too early to know exactly what will happen in the fall redetermination 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 years program and get us in to 2016.

Moving on to 2016 we want to give you some early preliminary directional guidance on what we're thinking. Our goal is Baird mention was 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 oil $60 oil in 2016. If these prices persist in to 2016, we could exceed our total debt leverage covenant a year from now. We are being proactive on this and I'm already talking with our 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 hedge 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 volumes. 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.

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 is a typo. We had it at $200 million to $215 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, Christy, we're ready to go ahead and take any questions.

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

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

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 (Inaudible) on a promoted basis where 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 are right, we have plenty of acreage and at this depressed oil price environment it makes sense for us to try to accelerate activity by having a viable partner 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 it is something we are actively pursuing and looking at this time.

Okay, makes sense. And then just two more quick ones. Baird, on that guidance you were just talking about the CapEx guidance. Can you just walk through I know you said the $200 mullion to $250 million and you thought based on what the rig activity would be I think you're thinking about 10% higher than that fourth quarter. Is that based on 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.

We have actually ratcheted down spending as we speak. In fact, we are down to one rig. We had 2 rigs, we let one of those two go. We're down to one. 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 in to 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. That is sort of the indication of how we expect production to be. And of course, if we find a JV partner and we decide to ratchet things back up of course, it would be probably a reduced working interest. It is undefined and undecided at this time of course, but in order to stay focused on liquidity that is how we've preliminary budgeted rigs.

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

Did you say costs Neal?

Yes, to obviously have some of those restrictions or some of those covenants change.

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

Okay. But nothing more than that?

No, no. A minor fee.

Got it. Okay. Thank you all.

All right. Thanks, Neal.

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

Good morning, everyone. Good morning. Just one 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 different proppant levels and doing slick water? I'm just trying to get that cleared up.

Yes, that is primarily it. It is a little bit more money involved with the slick water fracs and that is normalized to a 23 stage well and the others 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, but we think we can drive that down after we get on the learning curve a little bit.

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

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

Just to say one thing, Steve, to add on what John is saying. The $5.3 million we spent on some of the recent two-string well they were (Inaudible) run a $6 million, $6.1 million. So we actually reduced -- it was actually a lot less than what your expectations were. So if you take the $5.3 million and you add a million back in for a larger frac and a larger slick water frac you probably would get back up in to the $6.4 million range. Right off the bat if we can do what we did like in the Kudo wells for instance. It is something we think we can achieve fairly quickly but just for planning purposes we assumed higher costs this one time, but we think we have a good chance of getting it down pretty quick.

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

The upper Eagle Ford results really dragged down those IP that was the biggest culprit in driving those down and plus we had a couple of wells like I mentioned earlier that were only 21 stages so those came in at slightly less as well. But the lower Eagle Ford wells over all in all performed in line with the expectation but overall results were dragged down by the upper Eagle Ford.

And one other thing just to elaborate further as we have stated in the past our upper Eagle Ford has really a different decline profile then the lower. And yes, the IP and 30 day rates on the upper were below our expectations. We expect to see and have seen some lower levels of decline as we have seen when we had the higher IP and 30 rate. So it is consistent the type curve profile on these upper Eagle Ford wells appear to be consistent. We have not seen some precipitance decline in the upper just because they had a lower IP I just wanted to add that.

All right. Thanks guys.

Thanks, Steve.

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

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?

We reduced the sand, Brian, in the last couple of quarters, first and second quarter specifically from late last year. We had some indications at that time we had actually achieved a flattening where as 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 these recent data with these lower sand volumes it has 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 the 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 to show that we should be doing that but also the staggered and alternating patterns of upper and lower even if you pump less sand as we did on the on two upper RBK wells this staggered pattern and closer spacing and probably better frac capacity actually sort of seems to make up for lesser sand pumped if all that makes sense. So there is a couple things going on from a theoretical and a technical standpoint that we need to our arms around over time. And we will test this staggering and alterating pattern 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.

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

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

Yes, Brian, there is some noncore assets that we could sell. We have some assets that are not part of the contiguous block that we have been looking at trying to monetize. We feel very confident that that will happen. There is also the water system is still out there, we're still evaluating that. I don't think we are 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 lock and maybe looking at that. Granite Wash of course is still out there. So yes, there are some noncore assets that we could still look at monetizing and we are.

All right. Guys thank you.

All right. Thanks, Brian.

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

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 rate could be attributed to the reduced proppant per lateral stage?

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

I think it is 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 in the Kudo well two of those three were (Inaudible) and they were in a low GOR environment and they were very, very cheap to drill and they came in at some reduced rates. And that is probably irrespective of a sand loading issue as much of a rock issue and being in a lower pressure environment. I would say the less sand goes hand in hand with the completion configuration that 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 under performance to the lack of sand but it is probably 25% or something of that nature.

Okay.

You have to remember we continued even though we felt we had de-risk our upper across the majority our acreage the bulk of the program the second quarter program and late first quarter was sort of in our western Lavaca County acreage. As John it has a different characteristic that being lower gas content which of course, does effect the earlier time rates. It effects your early time rates on the lower. But to some extent it caught us by surprise. And at this point in time 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 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 in to account going forward.

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

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

No, that's fine. As you look at your roughly 100,000 acres in the Eagle Ford given what you have 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, you know, using the expected well cost with the new completion method and say using $60 oil?

We have some an acreage we have yet to test. We have roughly 11,000 acres that we picked up about a year or so ago that we need to get some drilled on that I would put in the (Inaudible) area at this time. We still think almost all of our acres is economic. In fact we could be drilling three-string wells assuming this 15% uplift because slick water fracs still show positive returns and adequate returns. The reason we backed off on the three-string wells is that it has a certain amount of 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 frac because your frac pressures are higher your frac rating tend to be somewhat higher than what we have in the shallower part. 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 have decided to back off for CapEx reason and return reasons at this time.

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?

I didn't hear the question. How many --

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

I thought I gave that. It was 26 to 28 net wells.

Okay, that's helpful. All right. Thank a bunch. I appreciate it.

Okay. Rich, thanks.

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

Good morning. Thank you for taking the question.

No problem.

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

Yes, I was thinking $100 million to $125 million, so yes, I think that is right on top of what we are thinking.

Okay. As you think about your exit for 2016 and lean to 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?

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 is a lot of time between now and then. I don't think we want to comment on that.

Sure. And then maybe just thinking about your comments generally on liquidity seems as though it is mainly focused on JV or assets sales. At what point does doing capital raise in say the forum like a second lien financing at what point does that make sense or how does that stack up against general assets sale plans in that sense?

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

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

Yeah, certainly is. It is something we'll continue to look at especially this kind of rig activity it is something we will keep our eye on. But if we stay on this kind of depressed environment it is something we'll have to take a look at no question.

Okay. And maybe Baird for you just kind of lastly when you think about the Eagle Ford JV concept would you consider doing just a JV in the upper Eagle Ford to help de-risk that and take your own capital off the table or how would you ideally describe a JV in the play?

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 include one or two of those wells within that overall package with a JV partner. So to answer your question that is 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 is something that will be definitely in the cards.

Okay. That is helpful. Thank you.

All right. Thank you very much.

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

Good morning everyone. 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 midpoint of guidance which is over 3,000 BOE per 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 any way.

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 half runs throughout the remainder of the year and that's a fairly sizable amount of the overall variance. The other thing that is going on is the program for the remainder of this year going into 2016 that being lower Eagle Ford up in Gonzales County has a different type curve associate with it, i.e., lesser IP, lesser 30 day rate but also has of course, much lesser joining 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.

So in the old CapEx what were you planning on doing in the second half in the upper Eagle Ford that is now shelved?

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

Okay.

I don't have anything handy.

Okay. Of the ten upper Eagle Ford wells that you reported that had the disappointing result were all of them frocked with the lower sand concentration.

Yes.

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

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

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

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

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

Okay. Thanks, Kim.

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

Good morning, everybody. I think most of my questions were answered but just a couple of follow-ups. On the CapEx number for next year is that total CapEx or is that just join and completion and if you can break out some ballpark on proportions.

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

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

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

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

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

Okay, great. Thanks.

Okay. Thank you, Adam.

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

Hi, good morning everyone. 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?

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

Okay, great.

Okay. Thank you.

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

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 everything took a big step down there.

Well, the biggest factor was spending fewer days on location. Most of those wells we were on and off in 13 days or less. That is the number one factor that drives your cost down. And then across the board we have seen 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 transitioned 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 ratchet up 18% over last year to over 1,060 feet per day.

Got you. I see. And that sounds that is going to be sustainable for the next few quarters at least, correct?

Yes.

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

It is minimal. We have about $7 million assumed for next year for facility cost which would include some line hooks up and supporting the water system. But it is minimal there. The vast majority of the costs are behind us.

I see. As far as water system and monetising that asset can you give me 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 would it need to be an entire asset sale? Can you just provide a little color around that.

We talk with the same bouquet M&A offset that helped us monetized the gas gathering system and the crude oil gathering system sales earlier. We're not pursuing it right this minute. We are not speaking to anyone right now, but at some point it is probably an asset that would make sense to be in the hands of an MLP or some other owner but not right now.

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

Yes. We operate it.

Okay.

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 evaporation process is being sold in some cases or being used internally for work over reasons. So timing is everything as far as when you try to sell something like this. Having a size to the system that is large enough that it makes a lot of sense to sell at that time is really the consideration. And it will be certainly in a much better situation 2016 to consider selling what it is currently.

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

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

I think we have about 25 or 26 (Inaudible) units formed in the Cypress undeveloped acreage. And each one of those units is approximately 640 to 700 acres. So probably on the order of 14,000 to 15,000 acres.

Okay, I see. All right. Guys, thanks very much.

All right. Thank you.

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

All right. Thanks, Christy. 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 remain confident in what we're doing both operationally and financially. In this challenging oil price environment we find ourselves in we are 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 have to keep our balance sheet healthy. We all realize what we have to get done, and everybody's mindset at this time is to do exactly that. We also realize that our declines in our equity and (Inaudible) prices have been significant, but ultimately we have confidence in our assets. And with a good asset which is almost impossible to replicate today we think we are going to be able to regrow the value of this Company. And lastly as Ed pointed out, I'll 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've very much enjoyed our discussion and communicating the Penn Virginia story. There is 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 I am thankful for the confidence the Board and the investment community has placed in me. And with that, I will say thank you and goodbye.

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