Penn Virginia Corporation
Q3 2015 Earnings Call Transcript

Published: 10 Nov 2015

[Operator:]

Good day, ladies and gentlemen, and welcome to the Penn Virginia Corporation Third Quarter 2015 Earnings Call. At this time, all participants are in a listen-only mode. Later, we will host a question-and-answer session, and instructions will follow at that time. As a reminder, this call is being recorded. I would now like to turn the call over to Edward Cloues, Chairman and Interim CEO. Sir, you may begin.

[Edward B. Cloues:]

Trisha, thank you very much. I'd like to thank everyone for joining us today for Penn Virginia's third quarter 2015 conference call. I'm joined today by members of our management team who include

[John A. Brooks:]

Thanks, Ed. I'm going to flip over to page four, which starts the third quarter 2015 operation summary. First off, as a reminder, we have approximately 100,000 net acres in the eastern volatile oil window of the Eagle Ford play with approximately 55% of that held by production and approximately 300 operated Eagle Ford wells, plus 36 outside-operated wells. As Ed mentioned, third quarter 2015 production was 20,976 BOE per day, slightly above the midpoint of the guidance range of 18,500 BOE to 22,800 BOE per day. Operational execution is on track, currently operating one drilling rig and one part-time frac spread. Our spud to TD cycle times have improved significantly in 2015 compared to previous years. For the third quarter of 2015, spud to TD averaged 8.67 days for an average lateral length of 4,930 feet, and an average measured depth of 16,128 feet. Our completions execution in the third quarter was also excellent, averaging approximately five stages a day of high-intensity proppant fractures, pumping over two million pounds of proppant per day, while we transition to the slickwater fracs. Our best drilling and completion performance in the third quarter came on our Chickenhawk, Jake Berger Cattle Co. two-well pads. The Chickenhawk 1-H reached TD of 17,225 feet with a 6,125 foot lateral in 6.15 days, and IP-ed at 2,897 barrels of oil equivalent per day, and 91% oil. Also on that pad, the Jake Berger Cattle Co. #1-H reached TD of 16,555 feet with a 5,409 foot lateral in 7.96 days. And that well IP-ed at 2,771 barrels of oil equivalent per day, and that was 90% oil. As mentioned, we transitioned to only two-string Lower Eagle Ford wells; and overall, our most recent Lower Eagle Ford results have exceeded expectations, specifically wells stimulated with slickwater and high-proppant volumes with the IP and 30-day rates 88% and 59% higher than the second quarter averages. On page five, total well costs, as shown here, continued to decline, driven by a transition to drilling exclusively two-string wells, whereas only three of the second-quarter wells were two-string wells. Additionally, all of the third quarter wells were stimulated with approximately 46% more proppant per stage, on average, than our second-quarter wells. Oil field service cost decreases have also benefited our operating costs, which declined from $32 million to $29 million during the third quarter. We expect operating cost to drop further in the fourth quarter due to the sale of East Texas at the end of August. The average well costs for 11 two-string wells turned in line during the third quarter of 2015, was approximately $5.7 million, down 30% from an average of $8.2 million for 16 wells, which included 13 three-string wells turned in line during the second quarter. Seven of the third-quarter wells and three fourth-quarter wells were stimulated using slickwater. Turning to page six, these seven third-quarter wells also averaged $5.7 million, which is considerably lower than we expected slickwater fracked high-intensity proppant wells to cost. Our operations team continues to execute efficiently at a high level. Drilling efficiency continues to increase as we have averaged 11,019 feet per day for 2015 through the first week of October, which is a 23% improvement over 2014. For completions in the third quarter, we pumped 189 stages with 100% success rate with plug-n-perf operations and a 97% success rate on coiled tubing drill-out. On slide seven, we show our trend can average quarterly IP and 30-day rates for our Eagle Ford wells with varying lateral lengths, a number of frac stages and frac intensity. On page eight, we try to normalize this by looking at IP versus proppant load per frac stage, and you can clearly see a direct correlation between the two variables. On page nine, normalizing the early production data for slickwater wells over a 6,000-foot lateral with 24 frac stages, you'll observe that the majority of these wells are tracking the higher type curve. As mentioned, we have three additional wells brought online over the past seven days and the early production appears to be consistent with these set of wells. And on page 10, that shows you the location of our third quarter drilling activity with the blue-shaded boxes reflecting data for wells which were both slickwater stimulated and zipper fracked, which we believe is resulting in the best stimulated rock volume and superior results so far. The next two pages summarizes IP data for our most recent Upper and Lower Eagle Ford wells. You can see the superior averages for the five slickwater zipper fracked wells on page 11. And the higher averages for Upper Eagle Ford wells that had more than 1,500 pounds of proppant per lateral foot. At this time, I'll turn it over to our CFO, Steve Hartman for the financial portion of the call.

[Steven A. Hartman:]

Okay. Thanks, John. I'll start with the review of our updated fourth quarter and full-year 2015 guidance on slide 14. Our production guidance for full-year 2015 is 7.8 million to eight million barrels of oil equivalent or 21,300 BOE to 21,800 BOE per day. This is down slightly from our previous full-year guidance. Fourth quarter guidance for total production is 1.5 million to 1.7 million BOE or 16,200 BOE to 18,100 BOE per day. Again, this is down slightly from our previous guidance. The slight reduction in guidance is due to the sale of non-core Eagle Ford assets, small adjustments over several wells drilled earlier this year with cross-link gel completions and some changes to the working interest in the third quarter with partner elections. Total product revenues including hedges are expected to be $77.5 million to $82.5 million for the fourth quarter, which would give us $399 million to $404 million of revenue, including hedges for the full-year. This was down from our previous guidance and is attributable primarily to our lower commodity price assumptions for Q4. We were previously assuming a $55 per barrel oil price for WTI. We are now assuming $45 per barrel in our forecast. We are expecting lease operating expense to be $5.45 to $5.84 per barrel in the fourth quarter. That is lower than the $5.86 we booked in the third quarter. The increase in third quarter LOE was primarily due to higher compression and saltwater disposal costs in East Texas, offset by lower work-over and chemical costs in the Eagle Ford. So, we don't expect those costs to go forward since we sold the higher costs in East Texas assets. Gathering, processing and transportation expense is expected to be $2.35 to $2.54 per barrel in the fourth quarter. This is down compared to the third quarter, primarily due to the sale of East Texas. Production and ad valorem taxes should be around 5.4% to 5.8% for the fourth quarter with the full-year tax rate at around 6%. Recurring cash G&A is expected to be $8 million to $9 million for the fourth quarter, consistent with the third quarter run rate. Non-recurring G&A should be around $500,000. DD&A is expected to be around $40 per barrel for fourth quarter. The rate picked up slightly due to the sale of East Texas. But we would expect that rate to come down in 2016 as we bring on lower cost wells. Adjusted EBITDAX is expected to be $52 million to $56 million for fourth quarter, which is lower than previous guidance due primarily to commodity prices. We would expect in 2015 with $280 million to $284 million of LTM adjusted EBITDAX. Capital expenditures have dropped dramatically since the beginning of the year. We expect to spend $35.5 million to $43.5 million in the fourth quarter, which is consistent with what we spent in the third quarter. Almost all of this capital is for drilling and completions, used to develop two-string locations in Gonzales and northwest Lavaca Counties. Our revolver debt at the end of the quarter was $140 million, pro forma for our borrowing base redetermination of $275 million. We have $136 million of liquidity with $2 million of letters of credit outstanding and $3 million of cash. We are expecting $15 million to $30 million of outspend in the fourth quarter, which would leave us with a $155 million to $170 million drawn and $103 million to $118 million of liquidity at year-end 2015. We reported total debt leverage this quarter at 3.9 times compared to our covenant of 4.75 times. Using the midpoints of guidance I just discussed, we would expect total debt leverage to be at around 4.4 times at year-end compared to our covenant of 4.75 times. As Ed mentioned, we're working on restructuring the balance sheet to increase liquidity and strengthen metrics. We can't comment on the process other than Jefferies have engaged to work on it and we're working hard on it. I can, however, comment on our redetermination in the bank group, but $275 million redetermination was within our expectations and takes into account the sales of both East Texas and the smallest non-core asset we sold in South Texas. The bank group has been supported by the company and we received unanimous consent for the redetermination. Moving on to preliminary guidance for 2016, we are now assuming lower oil prices in 2016 than we did in our last guidance. With the current oil strip at around $50 per barrel, we expect we would not ramp up to a two-rig program in early 2016 as we have previously guided, but would rather stay at a one-rig program until prices improve. With a one-rig program, we would expect to invest $140 million to $160 million in total capital. Most of which would be spent on drilling and completions. That would have us drilling around 20 gross well locations, 18 net. Our plan has us at around $15 million of non-drilling and completion spending, primarily landed facilities, and $15 million of contingency CapEx around planned well cost. We expect to drill primarily two-string locations in Gonzales and northwest Lavaca Counties. We expect we will continue with slickwater completions, higher proppant intensity and 600-foot spacing between laterals with zipper fracking as much as possible. We have not yet changed our type curve assumption for the new completions techniques and results. But if results remain as they've been, we expect that we could increase our type curve assumptions in the future. Using our current type curve and a one-rig program, we would expect oil production to decline around 5% and total production to decline around 10%. That's fourth quarter 2016 production over fourth quarter 2015 production, which we often referred to as our exit rates. On the next slide, I highlight our hedge portfolio. It has not changed since the last earnings call. We have 11,000 barrels per day hedged for the fourth quarter with 5,000 barrels hedged with a lower put struck at $70. The weighted average floor price for the fourth quarter is $89.86 per barrel. We have 6,000 barrels per day hedged for 2016 at a weighted average price of $80.41. These are all swaps with no lower puts. At the bottom right of the slide, we show our expected cash settlements, given various WTI pricing assumptions. At $50 oil, we would receive $31.1 million in cash settlements in the fourth quarter, and $66.8 million in 2016. And with that, that completes the financial update. Trisha, we can open up the line for questions.

[Operator:]

Thank you. And our first question comes from the line of Welles Fitzpatrick with Johnson Rice. Your line is now open.

[Welles W. Fitzpatrick:]

Hey. Good morning.

[Edward B. Cloues:]

Good morning.

[Welles W. Fitzpatrick:]

Can you talk a little bit to the longer-dated production from the Upper Eagle Ford wells, specifically the batch that you did with the higher proppant loading? How are you seeing those hold in?

[John A. Brooks:]

There was actually a mixed bag of results. Some of them performed on trend with the Lower, but there were a handful of them that did underperform that type curve. And that is one of the reasons that we have suspended this Upper Eagle Ford drilling for the time being and focusing on the Lower Eagle Ford. We do anticipate that we may have some Upper Eagle Ford locations drilled in 2016, but only when they are paired with an offset Lower Eagle Ford completion.

[Welles W. Fitzpatrick:]

Okay. Perfect. And I know you've spoken on this in the past. But could you remind us how much of the acreage is applicable to that two-string design?

[John A. Brooks:]

In terms of acreage, I would say a little bit less than 50% of our acreage is in the two-string window.

[Welles W. Fitzpatrick:]

That's perfect. Thank you so much.

[Operator:]

Thank you. And our next question comes from the line of Brian Corales with Howard Weil. Your line is now open.

[Brian Michael Corales:]

Yeah. Hey, guys. Good morning. The base of this is tag onto what Welles just asked, but are you all still testing, I guess, increased same content on the wells?

[John A. Brooks:]

Yes, we are. We've changed the stage spacing from 2014. It was 225 feet stages in 2014. Right now, we're at 250-foot stages and designing around 500,000 pounds of proppant per stage, which yields a target of 2,000 pounds of proppant per lateral foot. That's really the metric we're focusing in on is how much proppant per foot of lateral.

[Brian Michael Corales:]

Okay. And then maybe from 10,000-foot, I mean, based on the preliminary budget next year, it seems like you all would have confidence that some sort of – you're going to gain some sort of partner or increased capital. Could you maybe comment a little bit on that just based on cash flow versus projected CapEx?

[Edward B. Cloues:]

Yeah. This is Ed Cloues. I'll try to give you the answer from 10,000 feet without getting into specifics. But, we're actively looking at quite a variety of things. One could ask why we haven't done something already. Part of the answer to that is, we really needed to have the wells that we have now to serve as a launching point to do the kind of refinancing that we would like to do. And so, six months ago, nine months ago, we didn't really have that. We do have it now. We're very encouraged by the wells we have. And we think this good well is part of the key to being able to do an effective financing. So, we're looking at financing in multiple parts. We're looking at a financing initially that would not be something that gets re-determined every few months, but would provide us with more than the amount of capital we currently have available to us. We're looking, as we've said publicly, to do something with our balance sheet. And we're looking for a longer source of joint venture capital on specific assets to do drilling deals with and probably in that order in terms of accomplishing them. We're very – we're quite optimistic that we'll succeed in all of these efforts. As I say, we're very actively engaged in this process. But until we have something to announce, we won't be making any announcements or talking specifically about what we're doing.

[Brian Michael Corales:]

That was very helpful. And maybe just one tack on – are you all – it sounds like you're all in the late innings of this kind of redetermination of these events? I mean, are we at the seventh-inning stretch here or is this still just ongoing?

[John A. Brooks:]

I don't know how I'd characterize it exactly, but I would say we are well into the process.

[Brian Michael Corales:]

Fair enough. All right, guys. Thank you.

[Operator:]

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

[Richard M. Tullis:]

Hey. Good morning, everyone. A couple of quick questions. Are there any assets remaining that could be readily sold in this environment? I know you still have the Mid-Con. Anything there that's potentially a quick sale?

[Edward B. Cloues:]

You see, Mid-Con would be the most logical. There, of course, can be pieces in the Eagle Ford that we would consider for the right price. But, we're not in a position where we really need to think too much about that at the moment, because we have ample cash to last us for the next few months. And we expect before we have a real issue with that, that we will have accomplished some of the other things we've been talking about.

[Richard M. Tullis:]

Okay. And as far as the wells in Peach Creek that were drilled in the third quarter, how dispersed were those well across that acreage?

[John A. Brooks:]

There's a map, I think, in the presentation on page 10, if we can go to. You'll see that the northeastern part of the acreage was tested in the Jake Berger Cattle and Chickenhawk unit. That was a brand new unit with two wells straddling the unit lines based at 660 feet apart and that actually is two of the best wells that we've ever drilled and completed in the Eagle Ford. Proceeding down to southwest, we went to the Bertha unit, that was an existing unit that had one parent well on it. We drilled three zipper frac wells offsetting it. The first well was a three-well pad was, I believe, around 600 feet from the parent well, and then, all three of the new wells were below 400-foot spacing between pads. Moving further to southwest, the Oryx unit was a hybrid frac and then the next two down to the further southwest was our first slickwater frac was the Munson Ranch 11 and Munson Ranch 12, that was not a zipper frac. That was two opposing laterals. One of them relatively short, around 2,000 feet and those were drilled in between four existing wells that had been online for over three years. They were originally drilled on 1,200 foot spacing and the two Munson Ranch wells that we drilled and completed in the third quarter was 600-foot down-spaced wells. A little bit outward to that was our Hawn Holt unit 16 and Hawn Holt unit 17. And likewise, those were in between several cluster of wells, but specifically between two main wells that originally had been spaced on 1,200 feet. We zipper fracked those two. They were spaced on 400 foot, but they were not slickwater fracs, those were hybrid fracs.

[Richard M. Tullis:]

Okay. That's helpful John. Thank you. And Steve, I know you gave the guidance for 4Q, what do you think the actual December 31 exit rate range would be?

[Steven A. Hartman:]

I don't have that level of detail handy Richard. But since we are in a slightly declining range with the one-rig program, I'd say it's on the lower end of the guidance range...

[Richard M. Tullis:]

Okay.

[Steven A. Hartman:]

...but the beginning of the quarter being more on toward the higher end of the range.

[Richard M. Tullis:]

Okay. And then just lastly, is there still an ongoing search for a permanent CEO? Or do you guys just put that on the side for the time being?

[Edward B. Cloues:]

We've put it on the side for the time being until we complete the restructuring process that I talked about earlier in the remarks. We just felt there was too much noise going on trying to bring somebody in now. We have to get this completed and then really focus on that.

[Richard M. Tullis:]

Okay.

[Edward B. Cloues:]

But we were well into the effort.

[Richard M. Tullis:]

Okay. That's all for me. I appreciate it. Thank you.

[Operator:]

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

[Stephen F. Berman:]

Thanks. Good morning. The $5.7 million well cost, obviously, were down from prior numbers. Is there any more room to bring that down either through efficiencies or more service cost reductions?

[Edward B. Cloues:]

Yes. There is. We're currently drilling under a day-rate contract that expires in January of 2016. If we were to go get that contract today, if we anticipate it would be about $10,000 a day cheaper. So, that day-rate could come down. That's probably the single most contributing factor to additional lowering of our drilling costs. Also, a lot of the pads that we have drilled and completed in the third quarter were actually constructed earlier in the year under a different pricing environment. So, some of the higher-priced pads are already baked into that $5.7 million, and if we're able to replicate the TD cycle time that we had on the Chickenhawk and Berger, where we're drilling these 16,000 foot to 17,000 foot wells, in six days to seven days. That type of – if we repeat that, I think we can drive down further in its – at $5.7 million, I think that we can probably beat that. There's still room to shave another couple of 100,000 off of that.

[Stephen F. Berman:]

Got it. Thanks. And one more, if you have this level of detail, what's the LOE per BOE just for the Eagle Ford? I don't know if you have that.

[John A. Brooks:]

One second, Steve. Since, it's the majority of the volume and LOE, it's pretty close to what we reported. I just can't figure it out exactly.

[Stephen F. Berman:]

Pull all the specs...

[John A. Brooks:]

I don't have it. Let's see.

[Edward B. Cloues:]

We'll circle back to you, Steve.

[Stephen F. Berman:]

Okay. No worries. All right. Thanks, everyone.

[Edward B. Cloues:]

Thank you.

[Operator:]

Thank you. And our next question comes from the line of Sean Sneeden with Oppenheimer. Your line is now open.

[Sean M. Sneeden:]

Good morning. Thank you for taking my questions.

[Edward B. Cloues:]

Good morning.

[Sean M. Sneeden:]

How should I be thinking about the remaining inventory of Lower Eagle Ford location? I guess it's maybe one of the questions earlier. How many of those remaining locations are eligible for that two-string design that you're talking about?

[Edward B. Cloues:]

Well, in a SEC world, our PUDs are probably, undeveloped locations are in the neighborhood of 200, and that would be a mix of two-string and three-strings. Outside the SEC constraints on what you can drill with our current drilling pace of one rig over five years, they number in the hundreds and over 1,000 actually. And it really depends on how you break it out between two-string, three-string, and Upper and Lower. So, it's safe to say there's hundreds, I guess, is the scale, I would put it that not committing to a specific number. But as far as Lower Eagle Ford two-string wells, we've got over 100.

[Sean M. Sneeden:]

Okay. And it's the thought that all those Lower Eagle Ford two-string wells are – should be economic, we'll call it the strip today, or how are you guys thinking about kind of – in those terms? Or are we thinking about more in line with kind of the SEC kind of PUD number you gave me?

[Edward B. Cloues:]

Well, the individual well economics I think are very robust, what we're seeing with our current costs in the slickwater results. So, all of those, we consider to be economic, based on what we're seeing so far.

[Sean M. Sneeden:]

Okay. That's helpful. And then, maybe just kind of thinking about the PV-10 that you guys talked about in the Q, it seemed a little low to me. What was the main driver there? Was it just the movement to a one-rig program and some of them fell off, because of the five-year rule or was it price revisions or could you talk a little bit about that?

[John A. Brooks:]

Sean, it was mostly – it was commodity-price driven, but there is also a component of that for the five-year rule, when we went down to a one-rig program. So, we didn't lose drillable locations. But as far as the SEC definition is concerned, we did lose a large number of PUD locations.

[Sean M. Sneeden:]

Okay. And could you share what the price deck you guys use when calculating that?

[John A. Brooks:]

It's a trailing 12 months. I think it was around 72, at midyear.

[Sean M. Sneeden:]

Okay. So, it's based on midyear prices?

[John A. Brooks:]

It's trailing 12 months as of that time. So, there's about six months at the lower price deck, but we still have the midyear benefit of some higher months.

[Sean M. Sneeden:]

Got you. And then maybe just kind of lastly. Ed, just on some of your comments, it sounds as though the refinancing as you call it would not necessarily be deleveraging on its own but rather just added into liquidity. Is that kind of the right way to think about the first step of any kind of potential transaction?

[Edward B. Cloues:]

Well, I think that would be a fair assessment.

[Sean M. Sneeden:]

Okay. And so, deleveraging the balance sheet would be kind of like a second order effect after you kind of get the liquidity side of things, is that right?

[Edward B. Cloues:]

That would be how we see it at the moment, although certainly, we would be working on all of these things simultaneously. But in terms of the order in which it's likely to happen, I think that's a fair assessment.

[Sean M. Sneeden:]

Okay. That's helpful. Thank you.

[John A. Brooks:]

Sean, I also wanted to clarify one thing that when we were talking about our midyear reserves, the price deck I gave you was how we calculated the reserves. What we've reported in the 10-Q was using the strip as of the date we filed. So, I just wanted to clarify that.

[Sean M. Sneeden:]

Okay. So, that 614 is based off of this strip at 930?

[John A. Brooks:]

Correct.

[Sean M. Sneeden:]

Okay. That makes sense. Thank you.

[Operator:]

Thank you. And our next question comes from the line of David Snow with Energy Equities, Inc. Your line is now open.

[David G. Snow:]

I have one financial question. And I'm trying to get on the total BOE basis, what is your unhedged realization in the third quarter?

[Steven A. Hartman:]

And that would be – I don't have the exact number. But the number I have was, it was $42.40 for oil.

[David G. Snow:]

Okay. You don't have it for the total?

[Steven A. Hartman:]

I have it by the three components, so I can calculate it out. No, actually I don't have it handy. I have it by the three components, $42.40, $10.38, and $2.70.

[David G. Snow:]

Okay. Can you tell me does the zipper frac add uplift to the EURs or save money or both?

[John A. Brooks:]

We think both. Can you give the efficiency in the amount of work you can get done on a zipper frac, while you are pumping sand on one well you can be wirelined and perforating on another? So, you're able to just get a lot more done in a 24-hour period. As far as the well results, we think with the zipper frac you're likely increasing stimulated rock volume in revelizing the rock. So, we think there's an uplift there as well.

[David G. Snow:]

How close do you space the zipper fracs typically? There's well spacing?

[John A. Brooks:]

Based on below on the berth of wells, those were averaged 390 feet apart. On the Chickenhawk and Jake Berger well, they were 660 feet apart. And on the Munson Ranch wells, they were 600 feet from existing production. So, it's going to vary from 400 feet to 660 feet. I think going forward on just a notional basis, we're assuming 600-foot space for 2016.

[David G. Snow:]

And did you test the separate effects of doing either larger loadings of sand or slickwater as opposed to doing them both or have you not gone through that?

[John A. Brooks:]

Well, we had previously pumped high-proppant intensity fracs in conjunction with hybrid fracs in late 2014. So, to answer that question, yes, we've done that. And we had some good results, but as our Eagle Ford asset has matured and oil prices fell, the well performance from those hybrid fracs were not generating returns as robust as we thought they could be, so something had to change. So, the change that we made was to go to the slickwater; and in fact, we've been using slickwater in our fracs for quite some time. The previous frac fluid design consisted of pumping our initial fluid pad, which was slickwater, then changing over to a linear gel system and finally to a cross-link gel system all within each frac stage. The difference in the fluid design now is that we forego the last two fluid types and pump only slickwater. The simpler fluid design also has – costs a lot less as it requires fewer chemical additives. Slickwater stimulation has been successfully applied in several basins, but only in the last few months that we've become aware of successful slickwater fracs directly offsetting our acreage. From a small set of offset wells, we observed some outstanding production performance in essentially the same rock that we have. And the only difference we could determine from publicly-available data was the completion methodology, and it appeared to be high-proppant intensity slickwater fracs. So, while we had already tried the high-proppant intensity in the hybrid situation, which generated some good results but not as consistent as we would've liked, we've made the change to slickwater, which yields some outstanding results and at a lower cost.

[David G. Snow:]

Any ballpark as to what that could add to EUR uplift?

[Steven A. Hartman:]

You know, it's pretty early to start talking about EURs. I would say in the early time, back on page nine, if you look in the presentation, that lower black line shows you what our prior-type curve was forecasting. This is production cum oil versus time. And the black line is a notional 6,000-foot slickwater-type curve that we aspire to. So, you see, the early time difference at 90 days, there's about a 30,000-barrel delta in between the two. So, it is to accelerate that recovery early on, and that's probably the biggest driver of making those returns more robust, that along with the dramatically lower well costs.

[David G. Snow:]

Okay. I guess, the cost of these various improvements are actually less, including the proppant loading or is that – did I hear that wrong?

[Steven A. Hartman:]

No. You heard correct, they are less. We are now pumping these regularly under $70,000 per stage on the stimulation side. Previously, I think with the hybrids, those were closer to $90,000 to $100,000, and then we switched over to slickwater and we're getting in the $80,000s to $90,000s. Then we had a vendor change after we put it out to bid, and we've got it down below $70,000 per stage now.

[David G. Snow:]

What are the basins where they're combining slickwater and high-intensity sand loadings?

[Steven A. Hartman:]

I'm not sure I understand the question.

[David G. Snow:]

Well, I didn't think they were doing both together in the Bakken, but maybe they started doing it. What are the basins that they're using more sand plus slickwater together?

[John A. Brooks:]

No. We're really focused on the Eagle Ford and I can speak to our wells and the wells offsetting this. However, this has been used in several basins not only Eagle Ford, but the Permian and the Bakken.

[David G. Snow:]

Okay. And when you go to two-string, are you getting any change in output and reduction of EUR?

[John A. Brooks:]

I believe you asked, when we go to two-string because we are currently in two-string wells.

[David G. Snow:]

Yes. As opposed to three-string, are you losing anything there or getting the same performance?

[John A. Brooks:]

Well, we have not yet applied the slickwater high-proppant intensity fracs to the three-string area of our acreage yet. We anticipate testing that in 2016, perhaps as early as first quarter.

[David G. Snow:]

But based on comparable inflations, do you seem to be getting the same results?

[John A. Brooks:]

Actually, I think the upside there is at least equal. Based on core data, the oil in place for the three-string part of our acreage appears to exceed what the oil in place is for the two-string areas. So, I would say there's probably some more upside to actually getting it to work in the three-string area.

[David G. Snow:]

More upside in two-string or three-string?

[John A. Brooks:]

More upside in the three-string than the two-string, because of the higher oil in-place volumes there.

[David G. Snow:]

Okay. Okay. Thank you very much.

[Steven A. Hartman:]

David, I just wanted to let you know we did the math for you on the unhedged realized price. It's $31.45 BOE.

[David G. Snow:]

$31.45. Thank you very much.

[Operator:]

Thank you. And our next question comes from the line of Phillip Pennell with Mariner Investment Group. Your line is now open.

[Phillip Pennell:]

Yes. Thanks for taking my questions, guys. On the Munson Ranch property, did you find any communication issues with the previously drilled wells once you went back in there in down space?

[Edward B. Cloues:]

Yes, we did. We actually found it, while drilling on the number 11, we crossed a known fracture that we'd encountered in prior drilling. And we ended up having to cut that lateral short. It was supposed to be a 4,000-foot lateral, ended up just under 2,000 feet. And we lost about 800 barrels of oil-based mud while drilling that particular lateral. After we stimulated the 11, oddly enough, we recovered that 800 barrels of oil-based mud from one of these older wells that we had previously completed. I've never really recovered oil-based mud from a producing well before but that was – the only way for it to get whole mud was through an open fracture. So, we did see communication in that regard.

[Phillip Pennell:]

Is that all through your assessment of that property on a go-forward basis with the down spacing?

[John A. Brooks:]

No. If we did something different there, we would probably try to isolate the lateral where we would not communicate with the – in the open fracture system that could have been previously drained. But the rock is still – has a lot of oil left in the ground. So, we still like that area.

[Phillip Pennell:]

Okay. And in terms of the drill time results that you guys got, John, what do you assess the impact of, say, using your best crews? Or I mean, if you're down to one rig – and theoretically, you're using your best people. So, I'm wondering, how easily this efficiency that you've noted, which obviously is significant because you're talking about potentially like 40 wells a year off of one rig, given a couple of days to move it around and on pads, that's probably a reasonable assumption. I mean, do you think it can be generalized over to two wells at some point in the future?

[John A. Brooks:]

Well, I think if you look at the – not just the two wells I mentioned, but the average of the third quarter, it was repeatable. And it certainly has to do with good quality crews. But I think it also has to do with our – the way we're doing it. We retrofitted this rig. It's a Patterson rig that we took on a new build contract. We've made an investment in upgrading its pump systems in 2014 to 7,500 PSI fluid-ins, which gives us the ability to get another 800 pounds to 1,000 pounds of hydraulic pressure at the pit, which gives us a mechanical advantage at moving rock and cleaning the hole. So, we're real proud of the efforts that our drilling and completion teams have made. And it's something that we work to replicate. I think the drilling crews have a lot to do with this well though. And I have no reason to believe that we wouldn't be able to replicate it in a two-rig program.

[Phillip Pennell:]

Okay. And that's a good point that you made there in terms of upping the horsepower. I mean, if you're coming off contract on the existing PPI rig, I mean, are you looking to up the horsepower on what you get next, which may be you spend the same amount of money, which should get a better rig. I mean, do you look at upside wells...

[John A. Brooks:]

At our peak, we had eight rigs running. We had upgraded the pumps on three or four of those. So, obviously, we would want to bring back one of those that we already upgraded. And we actually have a first right of refusal on bringing that rig back to the field, if and when we go to a two-rig program.

[Phillip Pennell:]

Okay. And my last one is how many operating wells do you expect to end the year with?

[John A. Brooks:]

You kind of faded off there at the end of your question. I didn't quite catch it all.

[Phillip Pennell:]

Sorry. How many operating wells do you expect to end the year with?

[John A. Brooks:]

Well, we've got about 301 now. We're completing, getting ready to move on to a three-well pad, and probably between 305 and 310.

[Phillip Pennell:]

Great. Thanks.

[Operator:]

Thank you. And our next question comes from the line of Mark Kaufman with LPS Partners. Your line is now open.

[Unknown Speaker:]

Good morning. I just had a quick question about your estimate of liquidity for year-end and that takes into account the coupon payments that were made a few days ago on the senior notes?

[John A. Brooks:]

Yes. That's correct.

[Unknown Speaker:]

Okay. And would also encounter you recognizing the derivative gains that you mentioned for the fourth quarter, right? And so...

[John A. Brooks:]

Yes.

[Unknown Speaker:]

...ultimately, my real concern is, when I look at the working capital or I should say, your current assets, current liabilities, are there any issues around your vendors right now or any concerns with that in light of mentioning in your prepared remarks. The issue that you might be facing with your revolver?

[Steven A. Hartman:]

No. No. We have good relationships with all our vendors, and everyone is current. And so, there's no issues with vendors.

[Unknown Speaker:]

Okay. And if I may add one other question, you don't have to answer it. Would there be any issue about accounting firm, your accounting firm issuing a going concern letter, if you can't get the bank loan together before year-end or before the first quarter?

[Steven A. Hartman:]

Just what we disclosed in the 10-Q. That's all the disclosure that we needed to do with our auditors, so that's the level that we're at.

[Unknown Speaker:]

Okay. Thanks very much. Good luck, guys.

[Operator:]

Thank you. And our next question comes from the line of Robert DuBoff with Oppenheimer. Your line is now open.

[Robert DuBoff:]

Yes. Hi. Good morning, gentlemen.

[Edward B. Cloues:]

Good morning.

[Robert DuBoff:]

I apologize if I missed this earlier, but with the dropdown of one rig, what does your lease exploration schedule look like? How much you're going to need to spend over the next few years to extend leases? Are you just going to let from your Eastern acreage just to expire?

[John A. Brooks:]

Well, in 2016, we start seeing some undeveloped acreage expire that we obtain a couple of years ago. We can either extend it or re-lease it. I think there's 31,000 that expires in 2016. Some of that we can hold by drilling, some of it we can extend, some of it we'll probably just have to let expire. So, over the next two years, that 31,000 in 2016. There's another 17,000 up for exploration in 2017. And we would probably high grade that and just carefully target what we would want to extend or drill.

[Robert DuBoff:]

Okay. So...

[John A. Brooks:]

All of it is in area of East. It's not considered crude at this point.

[Robert DuBoff:]

Okay. So, does that $140 million to $160 million budget include lease extensions in those areas?

[John A. Brooks:]

A little.

[Steven A. Hartman:]

A little bit, not enough to cover all of that. We were considering that as a separate economic decision that we'd make in 2016 whether we would drill, hold, or let expire. We have $10 million, currently budget in $140 million to $160 million range or land and leasing.

[Robert DuBoff:]

All right. Great. Thanks very much.

[Operator:]

Thank you. And our final question comes from the line of Welles Fitzpatrick with Johnson Rice. Your line is now open.

[Welles W. Fitzpatrick:]

Hey, guys. Thanks for letting me hop back in. Just a quick question on the share-based advisory fee. Is there any kind of minimum type of transaction that would be needed to trigger that payment? I mean, would that go out of the door for something smaller like the, say, granite wash sale, or does it have to be more of a broader deal?

[Edward B. Cloues:]

It would not go out the door on a granite wash sale. That's entirely in our control in the sense that it would – we have to decide we wanted to do the kind of deals to which that fee would buy. And that fee – just to avoid any misunderstanding that people may have, that fee is not in addition to the normal cash fee we would have paid; and in fact, it's less. It's less than what we would have paid on the cash that it replaces. That is, if we would have paid what think would have been the cash fee, this would be valued – the stock would be valued at the – even today, we'd probably have a higher value than – lower value than what we would pay in cash. So, this is something that Jefferies wanted to partly to express their confidence in the company. In fact, that we were going to succeed in what we're doing, and to take part of their fee and stock rather than in cash from our point of view. We like that expression of confidence, and we like the fact that it reduced the cash outlay that we would have for some stock at a rate of price that we could sell equity for and raise money. But it's not a kicker. It's not an additional kind of fee. I mean, they're really at risk what the value was, and they gave up real cash to take the stock.

[Welles W. Fitzpatrick:]

Okay. That makes perfect sense. Thank you.

[Operator:]

Thank you. Ladies and gentlemen, that does conclude the question-and-answer session of this call. I would now like to hand the call back to Edward Cloues for any closing remarks.

[Edward B. Cloues:]

Thank you, Trisha. I hope you can sense from the call today that the group of Penn Virginia is an energized and optimistic group. I mean, we think we're going to work our way through these issues. Certainly, there's a lot of wood to chop. There's a lot of work to be done. I hope that I've dispelled any notion that as a "Interim CEO" I'm here in any kind of a caretaker role. I am fully engaged in what we're doing and in the big issues before the company. Management is fully engaged. We have a very optimistic outlook. And we hope that you've got a sense of that today in the call. And we hope that when we have our next call in a few months, there'll be a lot of new things to talk about. And with that, we'll close the call. Thank you very much for joining us.

[Operator:]

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