Ranger Oil Corp (ROCC) 2015 Q3 法說會逐字稿

Welcome to the Penn Virginia Corporation third-quarter 2015 earnings call.

(Operator Instructions)

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.

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 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, I'd like to remind you of the language in our forward-looking statement section of the press release, as well as the Form 10-Q, both of which were filed last night. As was the case in the last two quarters, we are using a slide presentation, which is out there on our website that we will go through simultaneously as part of the presentation.

Before turning this call over to John Brooks, our Chief Operating Officer and Steve Hartman, our Chief Financial Officer, who will provide an in depth look at the third quarter, I would like to cover three subjects. The first subject is a brief overview of our results. Third-quarter revenues and adjusted EBITDAX were within guidance despite lower than anticipated oil prices, while production was slightly above the midpoint of guidance.

Our recent well costs were 30% lower than the second quarter, due to our focus on drilling 2-string wells in our Peach Creek area and reduced pricing for services. Our operating costs have also fallen about 8% since the second quarter. Recurring G&A expenses fell about 12%. Due to the transition to one rig, our third-quarter CapEx was about 23% below the low-end of our guidance range and was 58% lower than the second quarter.

With the redetermination of our borrowing base to $275 million, which we expected, our pro forma liquidity at September 30, was $136 million. This liquidity should be adequate for a 2016 preliminary CapEx budget of $140 million to $160 million, assuming a $50 per barrel WTI oil price and a hedge book with 6,000 barrels of oil per day hedged at approximately $80 per barrel.

We are also very actively exploring additional ways to increase liquidity and decrease leverage. As John will touch on in his remarks, production in the Eagle Ford and overall was up on a pro forma basis year-over-year but was down sequentially due to the reduced pace of drilling. Finally, John will also report on the very dramatic improvement in our early-time well productivity, due primarily to the transition to slickwater stimulation zipper fracs and greatly increased frac intensity.

Now while good results are a key to our recovery, so too is strong execution of a coherent strategy. This is the second subject I'd like to comment on this morning. When I was appointed interim CEO on October 26, one of the first things I did was to address our employees and lay out a very aggressive but simple strategy for success that I wanted everyone in the Company to understand. Our investors should understand this strategy as well.

The Penn Virginia strategy has three tenets. First, we need to drill good wells. As you've seen from our news release and as you will hear from John and Steve, our most recent wells are among the very best we have ever drilled. The cost of these wells has been well-below our historical average. Good wells are the key to our survival and future success. They produce our results and they are what the rest of our strategy is built upon.

Our second strategic imperative is to restructure our balance sheet. We have too much debt and preferred stock. Our excellent Eagle Ford properties cannot reasonably be expected to support the totality of these obligations in the current oil price environment. You may be assured that we are working very hard on this subject. We will not discuss specifics in this call but we will make announcements as of when we have something to report.

The third and last element of our strategy is to find a reliable source of capital to support our drilling operations for the longer term. Once again, we are working hard on this but we will not give specifics in this call, although we will update the market again, as of when appropriate. If we can execute on this simple and straightforward strategy, and we are off to a good start with the success of our recent wells upon which everything else depends, we should be optimistic about our future.

The final subject I'd like to touch on is Baird Whitehead's retirement, which was erroneously reported by the Philadelphia Inquirer as a quote, abrupt departure. As you know, Baird had announced his intention to retire back in July, but had agreed to stay on pending the identification of his successor. The Board then launched an active search process with Spencer Stuart and has made considerable progress in this effort.

However, the Board recently determined that it should delay completing this process until the Company has completed the restructuring of its balance sheet, that I touched upon earlier. Under these circumstances, the Board felt that it was unfair to Baird to hold him to his commitment. Both the Board and Baird also reached the conclusion that my background was better suited than his for the tasks most immediately at hand.

As you will see from our very positive drilling results, Baird's departure had nothing to do with performance as has been speculated, but instead was a very natural part of the succession process. He will also remain on our Board, where his input on operations will be valuable, especially to me. I would like to emphasize that I did not accept the interim CEO position to be a caretaker or to be a babysitter of a declining operation.

Quite to the contrary, it's a job and a challenge that I welcome and am enthused to undertake. I would not have come out of retirement after two very successful careers if I were not confident that we could succeed in restoring Penn Virginia to good health. In fact, it's a prospect that I'm excited about as are our employees. We have an excellent team here at Penn Virginia.

We have a very good set of properties in the Eagle Ford. With a little help from oil prices, we have an excellent chance to succeed with the strategy that I outlined. No guarantees of course, but I like our odds, in fact, I like them a lot. With these preliminary remarks, I'm going to now turn the meeting over to John Brooks for an operations report. John?

Thanks, Ed. I'm going to flip over to page 4, which starts the third-quarter 2015 operations 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 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 5 stages a day of high intensity proppant fractures, pumping over 2 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 Company two-well pad. The Chickenhawk 1-H reached TD of 17,225 feet with a 6,125-foot lateral in 6.15 days and IP'd at 2,897 barrels of oil equivalent per day at 91% oil. Also on that pad, the Jake Berger Cattle Company number 1-H reached TD of 16,555 feet, with a 5,409-foot lateral in 7.96 days. That well IP'd at 2,771 barrels of oil equivalent per day. That was 90% oil.

As mentioned, we transitioned to only 2-string lower Eagle Ford wells. Overall, our most recent lower Eagle Ford results have exceeded expectations, specifically the 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 5, total well costs, as shown here, continued to decline driven by our transition to drilling exclusively 2-string wells, whereas only three of the second-quarter wells were 2-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. Oilfield service costs 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 cost for 11 2-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 3-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 6, these seven third-quarter wells also average $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've pumped 189 stages with a 100% success rates with plug-and-perf operations and a 97% success rate from coiled tubing drill-out.

On slide 7, we show our trend of 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 8, we try to normalize this by looking at IP versus profit load per frac stage. You can clearly see a direct correlation between the two variables.

On page 9, normalizing the early production data for slickwater wells over a 6,000-foot lateral with 24 frac stages, you will 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 seven wells.

On page 10, it shows you the location of our third-quarter driving 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.

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 8 million barrels of oil equivalent or 21,300 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 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 crosslinked gel completions and some changes to 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 in revenue, including hedges, for the full year.

This is down from our previous guidance and is attributable primarily to our lower commodity prices 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-cost East Texas assets.

Gathering, processing and transportation expense is expect to be $2.35 to $2.54 per barrel in the fourth quarter. This is down compared to 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 other 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 to end 2015 with $280 million to $284 million of LTM adjusted EBITDAX.

Capital expenditures have dropped dramatically since the beginning of the year. We expected 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, using developed 2-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 had $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 out spend in the fourth quarter, which would leave us with $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 had 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 has been engaged to work on it and we're working hard on it. I can, however, comment on our redetermination in the bank group.

The $275 million redetermination was within our expectations and takes into account the sales of both East Texas and the small non-core asset we sold in South Texas. The bank group has been supportive of the Company. 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 had 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 land and facilities and $15 million of contingency CapEx for unplanned well-costs.

We expect to drill primarily 2-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 result. But if results remain as they've been, we expect that we could increase our type curve assumption in the future. Using our current type curve in 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 slops with no lower puts.

At the bottom right of the slide, we show our expected cash settlements given various WTI pricing assumption. At $50 oil, we would receive $31.1 million in cash settlements in the fourth quarter and $66.8 million in 2016.

With that, that completes the financial update. Trisha, we can open up the line for questions.

(Operator Instructions)

Welles Fitzpatrick, Johnson Rice.

Good morning. Can you talk a little bit 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 holding?

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.

That is one of the reasons that we have suspended the 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.

Okay, perfect. And I know you have spoken of this in the past, but could you remind us how much of the acreage is applicable to that two string design?

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

That's perfect. Thank you so much.

Brian Corales, Howard Weil.

Hey guys, good morning. The base of this is a tag on to what Welles just asked, but are you all still testing increased same content on the wells?

Yes, we are. We changed the stage spacing from 2014. It was 225 feet stages in 2014.

Right now we are 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 is really the metric we're focusing in on, is how much proppant per foot of lateral.

Okay. And then maybe from 10,000 foot -- 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 increase capital. Can you maybe comment a little bit on that just based on cash flow versus projected CapEx?

Yes, his 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 of that is we really needed to have the wells 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 these good wells are the key to being able to do in effect, good financing, so we're looking at financing in multiple parts.

We are looking at a financing initially that would not be something that gets redetermined every few months but would provide us with more than the amount of capital we currently have available to us. We are looking, as we've said publicly, to do something with our balance sheet. And we are looking for a longer source of capital -- joint venture capital on specific assets to do drilling deals with. And probably in that order in terms of accomplishing them.

We're very -- quite optimistic that we will succeed in all of these efforts. As I say, we are 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.

That was very helpful, and maybe just one tack on. Are you all -- it sounds like you all are in the late innings of this redetermination -- or these events. Are we at the seventh-inning stretch here? Or is it still just ongoing?

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

Fair enough. Alright, guys, thank you.

Richard Tullis, Capital One.

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 is potentially a quick sale?

The Mid-Con would be the most logical. There are, of course, can be pieces in the Eagle Ford that we would consider for the right price.

But we are not in the position where we really need to think too much about that 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.

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

There is 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 line spaced at 660 feet apart, and that actually is two of the best wells we've ever drilled and completed in the Eagle Ford.

Proceeding down 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 roughly -- the first well of the three well pad was I believe around 600 feet from the parent well. And all three of the new wells were below 400 foot spacing between pads.

Moving further to the southwest, the Oryx unit was a hybrid frac, and the next two down to the further southwest was our first slick water frac was the Munson Ranch 11 and 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 in 1,200 foot spacing, and the two months Munson Ranch wells that we drilled and completed in the third quarter were 600 foot down spaced wells.

A little bit outward to that was our Hawn Holt unit 16 and 17 and likewise, those were in between several -- cluster of wells, but specifically between two main wells that had originally had been spaced on 1,200 feet. We zipper fracked those two. They were spaced on 400 foot, but they were not slick water fracs, those were hybrid fracs.

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?

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 would say it is on the lower end of the guidance range. With the beginning of the quarter being more on toward the higher end of the range.

Okay, and then just lastly, is there still an ongoing search for a permanent CEO, or have you guys put that on the side for the time being?

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

Okay, that's all for me. I appreciate it, thank you.

(Operator Instructions)

Steve Berman, Canaccord Genuity.

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

Yes, there is. We currently drilling under a day rate contract that expires in January of 2016. If we were to go get that contract today, we anticipate it would be about $10,000 a day cheaper.

So, that day rate can come down. That's probably the single most contributing factor to an additional lowering of our drilling cost.

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. Some of the higher pricing pads are already baked into that $5.7 million.

And if we are able to replicate the TD cycle time that we had on the Chickenhawk and Berger where we're drilling these 16,0000, 17,000 foot wells in six, seven days, that type of -- if we repeat that, I think we can drive that down further. And it's, at $5.7 million, I think that we can probably beat that. There's still room to shave another couple hundred thousand off of that.

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

Since it's the majority of the volume in LOE that's pretty close to what we report, let me see if I can figure it out exactly. I don't have it.

We will circle back with you Steve.

No worries. Thanks everyone.

Sean Sneeden, Oppenheimer.

Good morning, thank you for taking the questions. How should I be thinking about the remaining inventory of Lower Eagle Ford locations and I guess maybe to one of the questions earlier, how many of those remaining locations are eligible for that two-string design that you were talking about?

Well, in a SEC world, our PUDs, are probably our undeveloped locations are in the neighborhood of 200 and that would be a mix of two-strings 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 -- over 1,000 actually.

It really depends on how you break it out between two-stream, three-string, and upper and lower. So it's safe to say there is hundreds, my guess is, the scale that I would put it at, not committing to a specific number, but as far as Lower Eagle Ford two-string wells, we have got over 100.

And is it thought that all those Lower Eagle Ford two-string wells should be economic, we'll call it the strip today, or how are you guys thinking about that in those terms? Should I be thinking more about in line with the SEC PUD numbers you gave me?

Well, the individual well economics are very robust, what we're seeing with our current costs in the slick water results. All of those we consider to be economic based on what we've seen so far.

Okay. That's helpful. And then maybe just thinking about the TD 10 that you guys talk 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? Can you talk little bit about that?

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

Okay. Could you share what the price deck you guys used when calculating that?

It is a trailing 12 months, I think it was around $72 at midyear.

Oh, so it is based on mid-year prices?

It's between 12 months as of that time. So there's about six months of the lower price deck, but we still at the mid-year had the benefit of some higher months.

Got you. And then maybe just 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 additive to liquidity. Is that kind of the right way to think about the first step of any kind of potential transaction?

I think that would be a fair assessment.

Okay, and so deleveraging the balance sheet would be kind of the second order effect after you get the liquidity side of things fixed, right?

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

Okay. That's helpful.

Sean, I also want to clarify one thing. When we were talking about our mid-year reserves, the price deck I gave you was how we calculated the reserves. What we reported in the 10-Q was using the strip as of the day we filed. So just wanted to clarify that.

Okay so that [$614 million] is based off the strip at 9/30?

Correct.

Okay, that makes sense. Thank you.

David Snow, Energy Equities Incorporated.

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

I don't have the exact number, but the number I have was $42.40 for oil.

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

I have it by the three components. I can calculate it out, but I don't have it on handy, I have it by the three component. $42.40, $10.38, and $2.70.

Okay. I will just try to do it -- can you tell me, does the zipper frac add uplift to the EURs or save money or both?

We think both. When you get an 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 wire-lining and perforating on another. So you are 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 are likely increasing your stimulated rock volume and rubblizing the rock, so we think there is an uplift there as well.

How close do you space the zipper fracs typically in well spacing, horizontally?

Based on the below, on the Bertha wells, those were average 390 feet apart. On the Chickenhawk, 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 are assuming a 600 foot spacing for 2016.

Did you test the separate effects of doing either larger loadings of sand or Slick Water, as opposed to doing them both or have you not gone through that?

Well we had previously pumped high proppant intensity fracs in conjunction with hybrid fracs in late 2014, so to answer that question, yes, we have done that. We had some good results.

But as our Eagle Ford asset has matured and oil prices fell, the well performance results 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 slick water and in fact we been using slick water in our fracs for quite some time.

The previous frac fluid design consisted of pumping our initial fluid,, the pad, which was slick water, 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 slick water. This simpler fluid design also happens to cost a lot less as it requires fewer chemical additives.

Slick water stimulation has been successfully applied in several basins, but only in the last few months did we become aware of the successful slick water fracs directly offsetting our acreage. And 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 slick water fracs. While we had already tried the high proppant intensity in a hybrid situation, which generated some good results but not as consistent as we would've liked, we made the change to slick water, which yields some outstanding results and at a lower cost.

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

It's pretty early to start talking about EURs. I would say in the early time back on page 9, if you look in the presentation, that lower black line shows you what our prior type curve was forecasting. This is production [cumulative oil] versus time and the black line is a notional 6000 foot slick water type curve that we aspire to.

So you see the early-time difference at 90 days, there's about a 30,000 barrel delta between the two. So it tends 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.

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

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 hybrid, those were closer to $90,000 to $100,000 and then we switched over to slick water and we are 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.

What other basins are they combining slick water and high-intensity sand loadings?

I'm not sure I understand the question.

I did not think they were doing both together in the Bakken, but maybe they started doing it. What other basins are they using more sand plus slick water together?

No, we are really focused on the Eagle Ford, and I could speak to our wells and the wells offsetting us. However, this has been used in several basins, not only Eagle Ford, but the Permian and the Bakken.

Okay. Is it, when you go to two-string, are you getting any change in output and production or EUR?

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

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

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

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

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.

More upside in two-string or three-string?

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

Okay. Thank you very much.

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

$31.45. Thank you very much.

Phillip Pennell, Mariner Investment Group

On the Munsen Ranch property, did you find any communication issues with the previously drilled wells once you went back in there and down spaced?

Yes we did. We actually found it while drilling on the number 11. We crossed a known fracture that we had encountered in prior drilling and we ended up having to cut that lateral short. It was supposed to be a 4,000 foot lateral, it ended up just under 2,000 feet.

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 the older wells that we had previously completed. I never really recovered oil based mud from a producing well before, but that was the only way for it to get it hole mud was through an open fracture. So we did see communication in that regard.

Does that alter your assessment of that property on a go forward basis with the down spacing?

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

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 are? If you're down to one rig, then theoretically you're using your best people.

So I am 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 days to move around and on pads, that is probably a reasonable assumption. You think it can be generalized over to two at some point in the future?

I think if you look at the, not just the two wells I mentioned, but the average for the third quarter, it was repeatable. It certainly has to do with good quality crews, but I think it also has to do with the way we're doing it. We retrofitted this rig, it's a Patterson rig that we took on a new build contract.

We 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 bit, which gives us a mechanical advantage of moving rock and cleaning the hole.

I'm real proud of the efforts that our drilling completion teams have made and it is something that we work to replicate. I think the drilling crews have a lot to do with it as well though. I have no reason to believe that we would not be able to replicate it in a two-rig program.

Okay. That is a good point that you made there in terms of upping the horsepower.

If you are coming off contract on the existing PTI rig, are you looking to up the horsepower on what you get next, which maybe you spend the same amount of money but you get a better rig? Do you look at upside as well?

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.

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

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

Sorry, how many operating wells do you expect to end the year with?

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

Great. Thanks.

Mark Kaufman, LPS Partners.

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

That is correct.

And that would also encounter you are recognizing the derivative gains that you mentioned for the fourth quarter right?

Yes.

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

No, we have good relationships with all our vendors and everyone is current. There's no issues with vendors.

Okay. If I may add one other question. You don't have to answer it.

Would there be any issue about 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?

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

Thanks very much. Good luck guys.

Robert DuBoff, Oppenheimer.

Good morning gentlemen. I apologize if I missed this earlier, but with the drop-down to one rig, what does your lease expiration schedule look like?

How much are you going to need to spend over the next few years to extend leases? Are you just going to let some of your eastern acreage just expire?

Well in 2016, we start seeing some undeveloped acreage expire that we obtained a couple years ago. We can either extend it or release it. I think there is 31,000 that expires in 2016, some of that we can hold by drilling. Some of it we can extend. Some of it we will probably just have to let expire.

Over the next two years, that 31,000 in 2016, there is another 17,000 up for expiration in 2017. We would probably high-grade that and just carefully target what we would want to extend or drill. All of it is in areas east, it is not considered proved at this point.

Does your current -- does that $140 million to $160 million budget include lease extensions in those areas?

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

Alright great, thanks very much.

Welles Fitzpatrick, Johnson Rice.

Hey guys and thanks for letting me hop back in. Just a quick question on the share base advisory fee.

Is there any minimum type of transaction that would be needed to trigger that payment? Would that go out the door for something smaller, like say a Granite Wash sale or does it have to be more of a broader deal?

It would not go out the door on a Granite Wash sale. That's entirely in our control, in the sense that we would have to decide we wanted to do the kind of deal to which that fee would apply.

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 than what we would have paid than for the cash that it replaces. That is if we would have paid what we think would have been the cash fee, this would be valued -- the stock would be valued at even today, would probably have a higher value than the -- a lower value than what we would have paid in cash.

So this is something that Jefferies wanted, partly to express their confidence in the Company, and the fact that we were going to succeed in what we're doing, and take part of their fee in 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 greater price than we could sell equity for and raise money.

But it's not a kicker. It's not an additional kind of fee. They're really at risk what the value is. They gave up real cash to take the stock.

That makes perfect sense, thank you.

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.

Thank you, Trish. I hope you can sense from the call today that the group at Penn Virginia is an energized and optimistic group. We think we're going to work our way through these issues.

Certainly there is a lot of wood to chop, there's a lot of work to be done. I hope that I have dispelled any notion that as a quote, interim CEO, I am 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 got a sense of that today on the call. We hope that when we have our next call in a few months, that there will be a lot of new things to talk about.

With that we'll close the call. Thank you very much for joining us.

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.