Ranger Oil Corp (ROCC) 2014 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Penn Virginia Corporation third-quarter 2014 earnings call. At this time, all participants are in a listen-only mode. Later, we will conduct a question and answer session and instructions will follow at that time.

(Operator Instructions)

As a reminder, this conference is being recorded. I would like to introduce your host for today's conference, Mr. Baird Whitehead, CEO and President. Sir, you may begin.

Thank you very much. Thank you all for joining us today for our third-quarter 2014 conference call. I'm joined today by members of our management team including John Brooks, our Chief Operating Officer; Nancy Snyder, our Chief Administrative Officer; Steve Hartman, our Chief Financial Officer; and Jim Dean, our Vice President of Corporate Development.

Prior to getting started we would like to remind you of the language and a forward-looking statements section of the press releases issued yesterday as well as our Form 10-Q which was filed last the night.

We're very pleased with our third quarter results. We exceeded the upper end of a brand of production guidance and delivered continued strong cash flows and margins for the quarter.

The potential for production and reserve growth in the Eagle Ford is substantial, and we are well-positioned within it the considering our 104,000 net acre position that is blocking and contiguous. We have confidence in the excellent quality of this asset, including what we consider to be significant potential in the upper Eagle Ford.

The third quarter production was 22,700 barrels equivalent a day, which was 4% higher than the second quarter, while in the Eagle Ford itself production increased 8% quarter over quarter to almost 17,000 barrels a day equivalent. Our IP rates continue to reflect increased productivity due to our transition to pad drilling over the past year and a half. Our operating wells had an average IP rate of 1,350 barrels equivalent per day, and we had five notable wells with IPs over 1900 barrels a day equivalent.

These five wells included the Cinco J Ranch 1, which tested about 2600 barrels a day equivalent, the L&J Lee number 2, which tested 2200 barrels a day equivalent, the L&J Lee 1, which tested 2100 barrels a day equivalent, the Porter 6, which tested 2000 barrels a day equivalent, and the Porter 7, which tested about 1900 barrels a day equivalent. Year to date through the third quarter we've turned in live 66 wells now, which includes 6 shallow wells and 5 non-operated wells.

In September, our production from the Eagle Ford averaged nearly 18,000 barrels a day versus 16,900 barrels a day equivalent for the previous quarter. Three quarters of it, which was oil, and we expect further growth in Eagle Ford during the balance of 2014. In fact, through the approximate first 20 days of October we are still producing from the Eagle Ford itself about 18,000 barrels a day, but we have a tremendous amount of completion activity going on right now. We expect to ramp that up considerably as the quarter further progresses.

We've also picked up an additional 2500 net acres via leasing during the quarter at an average cost of about $1700 per acre. We're beginning to see acre cost now beginning to drift down. Our total net acreage, as I mentioned previously, is about 104,000 net acres today.

From an operational perspective we remain focused on continuing to improve the execution of our completions. As I have described in the past, we are in the process of transitioning to a larger production casing to drive improved completion performance.

By the end of year we expect to have cycled through all of our completions associated with the 4-1/2 casing and going forward, 5-1/2 casing will be our a predominant production casing which we think are going to continue to further lessen our completion issues. We've also revised other completion procedures including our wireline Plug and Perf [Pro Time] process and all these new processes we have implemented are helping.

During the second half of the year we have initiated further testing of the upper Eagle Ford across our Lavaca County acreage. We are testing not only its potential across this acreage, but again, whether it's separate reservoir from the lower Eagle Ford.

Just to remind everyone, we now plan on spudding 18 upper Eagle Ford wells during second half of this year, 7 which offset the very prolific Welhausen A2 well that was drilled in the southeastern part of our acreage and was drilled earlier this year. The other 11 wells we're going to drill are going to test various other portions of our Lavaca County acreage.

During the quarter, we drilled and completed six upper wells and during the first half of the year we also drilled and completed the Welhausen 2 and Martinsen 2, which we now consider our discovery wells, so year to date we have drilled and turned in line eight upper Eagle Ford wells. These two early upper Eagle Ford wells drilled in the first half of the year continue to perform fantastically. The Welhausen 2H which was turned in line in March at peak rate of about 2200 barrels a day equivalent, cumulative production to date of over 179,000 barrels equivalent.

The Martinsen 2 well, the other well, was turned in line in May. Had a peak rate of almost 1600 barrels a day equivalent and has produced also about 179,000 barrels equivalent. Even though the Martinsen had a lower IP than the Welhausen it has actually outperformed the Welhausen, making similar cumulative production but in a shorter time period. These are both excellent wells with what we now think are ultimate reserves both in excess of the million barrels equivalent.

Of the six wells completed in the third quarter, the Welhausen 7 and 8 wells were just turned in line are still cleaning up. The Hinze number 2 and number 3 wells have recently been completed and are in the early stages of cleanup. And Netardus 2 and 3 wells have not been final tested but have been producing to sales about 25 days now.

Right now the Netardus 2 is making about 650 barrels a day and almost 2 million cubic feet a day of gas. That will continues to improve over time. The Netardus 3 is producing about 250 barrels a day and about 900 Mcf a day, but its production is currently restricted down hold because we have an obstruction that will be fished out of a later date, but we think Netardus 3 well without that restriction it would have been as good if not a better well as the number 2 well.

One observation we have on these early upper Eagle Ford wells is that the initial decline rates are less than what we have typically seen with the lower Eagle Ford, indicating that the IP rates do not necessarily tell the complete story concerning what we consider ultimate reserves. In addition, the initial cleanup characteristics are different from the upper Eagle Ford wells. It appears the upper wells continue to bring back higher volumes of frac fluids over a long period of time, whereas the water volumes declined significantly to lower Eagle Ford due to an absorption of the water itself by the shale, the natural fractures of the more calcareous upper section, actually improves water recovery and probably is a reason for the lower initial decline rates once the peak rate is reached.

For this reason, if you look at the two Netardus and two Welhausen wells, at a minimum these wells have been flat, but actually two out of the four wells continue to improve over a long period of time. So we're very, very encouraged with what we're seeing in the upper Eagle Ford at this point in time. The lower initial decline rates and the fact that the upper wells clean up differently than the lower wells also gives us increasing confidence that the upper and lower are separate reservoirs.

During the fourth quarter of 2014 and into early 2015, we will continue to drill and test the upper Eagle Ford across the Lavaca County acreage and be able to say definitively, we think, probably by the end of the first quarter next year what we have, what the potential is, and also of course, as important or more important is the issue whether the two reservoirs are actually separate. As Steve will describe in more detail, we are in an excellent position financially to continue to fund this Eagle Ford growth and have the ability to adjust our expenditures to maximize the return on the capital we deploy.

Turning a moment to the balance sheet and liquidity position. As you saw in the press release, last week we have expanded our borrowing capacity on our overall liquidity increased to about $620 million as of the end of the quarter. At the same time, our leverage ratio decreased from 3.1 times at the end of June to 2.6 times at the end of this third quarter.

We are confident that our improved liquidity will allow us to leverage our prime position in the lower Eagle Ford and simultaneously continue to exploit what we now consider is a significant up side in the upper Eagle Ford. That said, we are acutely aware of the current commodity price environment as we look into 2015, and for that reason, we are reassessing our capital expenditures plan to bring our expenditures in line with current pricing levels while efficiently allocating capital to the highest return opportunities we have on our portfolio. We remain confident in our ability to drive production growth and increase cash flow, and we will provide a revised view of our CapEx program for 2015 either in December or right after the first of the year after our 2015 budget is finalized.

I just want to be clear, our decision to reassess guidance in no way reflects the change in our views regarding the quality of our assets. Our focus remains on continuing to improve our efficiency as we drill high-quality, high-return wells, and we are confident that we have the liquidity and financial flexibility to fund growth and drive shareholder value as the environment continues to evolve.

At this time, I'd like to turn the call over to John Brooks so he can give you some more additional operational detail.

Thank you, Baird, and good morning. Baird has discussed our third-quarter operational highlights in a fair amount of detail, so I will add just a few things.

We have a substantial number of wells yet to turn in line in the fourth quarter. 12 wells are currently completing or flowing back, including 6 upper Eagle Ford wells. We have 14 wells also waiting on completion, including another 6 upper Eagle Ford wells and 8 operated wells are currently being drilled in 3 of those are upper Eagle Ford wells.

Overall, we expect to turn in line 33 operated wells, excluding shallow wells, during the fourth quarter of 2014 for an estimated total of 88 operated wells to be turned in line during 2014, excluding shallow wells, and this includes 18 upper Eagle Ford wells.

Our Eagle Ford acreage has an undrilled location inventory of approximately 1600 locations. Approximately 600 of these locations are in the upper Eagle Ford, and over 1000 locations are in the lower Eagle Ford with the potential for another 400 upper Eagle Ford locations overlying our lower Eagle Ford in the Western Lavaca County area.

In the third quarter our average well cost was approximately $9.4 million overall with our two stream wells averaging $8.5 million and our three stream wells averaging $10.2 million. On a per stage basis, total wells cost in the third quarter averaged $358,000 per stage, with the two stream wells averaging $348,000 per stage, and three stream wells averaging $366,000 per stage. Total profit comped average approximate 10 million pounds per well. Of the 17 wells we turned in line in the third quarter, the average amount of profit pumped was approximately 368,000 pounds per stage or approximately 1700 pounds of profit [preferred] lateral.

We averaged 4.4 frac stages per day per pad during our stimulation operations in the third quarter and that contributed to our exceeding guidance production in the third quarter. We've refitted two of our drilling rigs with the 7500-psi fluid ends on their mud pumps which yields additional hydraulic horsepower resulting in faster drilling ROP's, a third refit is underway and a fourth refit is expected to be complete by January 2015.

For the first half of 2014, utilizing these and several other innovations, we've increased our effective footage drilled per day by 17% as of October compared to 2013. We are in receipt of our service providers stimulation contracts for the next 12 months and they are under final review. These contracts are one-year pricing arrangements, and we are confident that any unit cost increases will not be substantial and can be mitigated by the improvements we have made in optimizing completion design. Additionally, the contract terms are flexible enough to keep us from being locked into out-of-market prices.

Looking forward, the most significant drivers for further cost reduction will be continued efficiency gains both in drilling and completion. On the drilling side it's possible we can further reduce time and location by two or more days per well with the increased ROP's mentioned earlier, and on a three-well pad that could save a weeks' worth of time and money.

On the completion side we continue to optimize our frac designs which ultimately results in completing more stages per day at a lower cost. While we averaged 4.4 frac stages per day in the third quarter, it is not uncommon for us to achieve six and seven stages per day. Sustaining that pace of execution is the challenge.

That concludes my operational update, and at this time I'll turn it over to our CFO, Steve Hartman.

Thanks, John. The financial results are summarized in the release, so I won't go through that detail, but as Baird stated earlier, we are pleased with our strong cash flow margins for the quarter. I would like to highlight our lease operating expenses. It was higher than our typical run rate.

We had some one-time work-overs and a catch up charge for compression expense that made our per-unit cost higher than usual. We are still comfortable with the run rate per unit cost of about $5 to $6 per Boe going forward.

So, with that, I'll just move on to our capital resources and liquidity. As of the end of the quarter we had $124 million of cash on the balance sheet and we have a credit facility borrowing base of $500 million. Our pro forma total liquidity was $622 million net of letters of credit.

We brought in $250 million of cash during the quarter, $250 million of that was from non-core asset sale proceeds and $35 million was a final arbitration cash settlement related to our acquisition of Eagle Ford properties in April 2013. None of these proceeds required any pro forma adjustment to our trailing 12-month EBITDAX for calculating our leverage ratio, so our leverage improved significantly this quarter.

We reported leverage of 2.6 times for the quarter compared to 3.1 times at the end of the prior quarter. And of you annualize our third quarter EBITDAX, our leverage is 2.4 times.

Our credit facility which matures in 2017 is completely undrawn at this point. Our two publicly traded bonds mature in 2019 and 2020, and we have no debt maturities for the next 2.5 years. This combination of no near-term maturities and ample liquidity gives us the flexibility to adjust our drilling program in response to the current industry conditions, and we are confident in our ability to continue to do so should the current downturn persist.

Now, looking at our guidance update we are increasing our 2014 CapEx guidance to $754 million to $800 million. This implies fourth quarter guidance of $197 million to $243 million. At this time, we are planning to run the eight rig program through the quarter. We expect to turn in line 31 gross and 21.2 net wells.

The higher CapEx is tied to the higher steel costs associated with our transition to 5-1/2 inch casing in Lavaca County and just generally higher completion costs. We expect well costs will come down in 2015 with continued lower commodity prices, but we are not planning for these cost reductions in the fourth quarter.

We are also raising our land guidance slightly based on leasing activity we saw in the third quarter, but I wouldn't expect us to be very aggressive in adding land in the fourth quarter, mostly just adding land form drilling units in our current footprint.

We are reaffirming our production guidance for the year at 8.4 to 8.6 million barrels of oil equivalent. That implies fourth quarter production of 2.4 to 2.6 million Boe or 25,900 to 28,200 Boe per day. At the mid point of guidance, this is almost a 20% sequential increase.

For our oil production, we are guiding to 4.9 to 5 million barrels of oil. That implies fourth quarter production of 15,850 to 16,935 barrels per day. At the mid point of guidance, that would be at 21% sequential increase.

For adjusted EBITDAX, we are decreasing our guidance in response to lower commodity prices to a range of $387 million to $427 million. This implies fourth quarter guidance of $100 million to $140 million. This assumes a WTO oil price of $82 for October and $80 for November and December.

Our volumes are well hedged for the fourth quarter and through 2015 for that matter. For the fourth quarter we have 13,000 barrels of oil per day hedged, which is 79% the mid point of guidance at a weighted average for a price of $92.92. The hedges are doing their job of protecting our cash flow. If WTI averages $80 for all the fourth quarter, we will receive $15.5 million in cash proceeds.

As I mentioned earlier, our liquidity remains strong, we expect to end the year with nothing drawn on the credit facility, liquidity of approximately $500 million, and leverage of around 2.6 to 2.7 times. With liquidity of $0.5 billion, leverage below three times, and hedges on 13,000 barrels of oil per day in the first half of 2015 and 11,000 barrels of oil per day in the second half of 2015, we are confident in our ability to fund a drilling program that enables us to grow production and grow cash flow in 2015 while generating appropriate returns and driving shareholder value. We look forward to providing details on the 2015 plan in December or early January.

And, Baird, that's it for the financial review.

Alright. Thanks, Steve. We're ready to go ahead and take questions, please.

(Operator Instructions).

Neal Dingmann of SunTrust.

Morning, guys. Baird, obviously question is going to be on just when you look at spending for next year, including if you're able to pursue that stock buyback. I guess question for you or for Steve, how do you guys think about sort of that as part of your spending or how are you going to sort of integrate that?

I'm wondering on a total spend which, to me, I guess I'm including if you buy some stock back how you look at that. So I guess the two-part question. One, would that just be a total part of -- if you're going to spend 5% or 10% less next year would that include if you add some stock buyback on that. And then secondly, just how -- when you come up with that plan in the latter part of this year based on pricing, is there a certain level from debt to EBITDA or some other metrics that you want to stay behind as far as spending goes?

Neil, at this time really would be any decision we may make on a share buyback would just be part of our overall optionality as part of our CapEx program. Sit back and look directionally to see what oil prices are doing, we take into account the returns that we can generate at those kind of pricings, and we will also weigh within that analysis of the option to buy back some shares, but it would be all-inclusive. It would not be coming up with something and then adding a share buyback on top of it, if that makes sense.

We'll deal within a certain total range of CapEx and either allocated to all drilling, allocated to part share buyback or drilling, or various scenarios, but at this point in time we are still working through what we're going to do, but that would be our logic.

No, that makes sense. And then secondly a question for you or John. Just looking at plans for next year, and obviously I think in the press here where you outlined just some of the different IP and 30-day rates. When you look at either the beer quad or some of the Rock Creek Bozka area and some of the higher areas, how does that factor in where you'll drill next year? Is it just simply you'll go after just the best areas or is there still a fair amount of leases you have to hold? How should we think about now, with over 100,000 acres attacking that next year?

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

No, that makes a lot of sense and then, lastly, obviously there's still some concern just on execution, et cetera just right there on the operation, so I guess my question is you mentioned the larger case, different things around that. Doing some of these and some of the efficiencies that John mentioned, just your confidence level of execution because of some of these different advances now that you've put into place how you look at that going into 2015 if you think you've solved a lot of the issues that you had earlier this year?

Yes, I will let John answer some of this, too, of course, give you some more detail but, yes, we're getting better at it all the time, even on the 4 1/2 completions we're getting better at it. So, John, why don't you get a little bit more detail what we've done to improve things.

Sure. We've improved the operational execution by making some adjustments in our completion procedures. To give you some details, we've modified our pump down procedures with more tightly controlled pump rates and tool string velocities to better accommodate a specific well bore trajectory. We geosteer these wells in a fairly tight window and so we can loosen that window and make things easier for ourselves and that model it beforehand to make sure we're pumping at the right rates and pressures to minimize risks.

The other thing is adjusting the fluid rheology and the flush volumes following our profit placement which basically entails pumping gel sweeps to flush the well bore clean of sand following the proppant-laden slurry of the frac stage. This in itself isn't particularly new, but what we've done is more tightly engineered the sweeps specific fluid properties and volumes to ensure there's no stand left in the well bore to minimize a mechanical risk of both running in the hole and pulling out of the hole.

Another area where we've made some significant improvements is in our coal tubing drill outs. As we stated before, Penn Virginia provides its own drilling fluids and fluid engineers and we've extended that to provide engineering fluid support on our coil tubing drill outs. This has reduced our average time for coil tubing drill outs to less than two days per well. And then there's a host of several other details, but all of that just combines to give you more stages per day at a lower cost.

We are getting better all the time and we've seen a lot of improvement. We think we can continue to better over time and our goal is to get to that six to eight stages per day per pad would be our goal routine.

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

Brian Corales of Howard Weil.

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

John, why don't you -- it's probably higher than normal.

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

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

Next week or two.

So, we'll have four [runnages] to get caught back up some, but we are extremely busy on the completion side right now.

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

I would say about roughly half of it is perspective for the upper based on what we've tested so far. There is some additional testing to be done to the northwest up in Peach Creek that can test some other more northerly Upper Eagle Ford opportunities which hopefully we get to here in the fourth quarter or early first quarter. Then there's probably about one-third of it that's prospective for both. And thus far you haven't seen any communication between upper and lower testing when tested? No. Based on what we have seen on the flow backs, based on how these things act, their initial production, it's flat, as I said inclining in some cases it acts completely different than the lower. Typically you can establish peak rate on the lower in a very short period of time because the water (inaudible) can die substantially in a short period of time, so it acts completely differently on the flow back and the early production profiles of these things, so I think nothing is ever a slam dunk and what we have seen so far gives us quite a bit of confidence they are acting as two separate reservoirs, Brian.

Okay, guys. Thank you so much.

Steve Berman of Canaccord Genuity.

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

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

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

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

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

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

Okay. Great. All right. Thanks, guys.

Scott Hanold of RBC.

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

If you look at the Martinsen, we actually have in our public presentation there's a slide that shows the performance of the Welhausen and the Martinsen wells. The Welhausen had somewhat of a higher initial decline. The Martinsen well there was very little decline. It's just about as flat as you can see at this point in time I think on the Martinsen whereas the two have actually crossed, the Welhausen and Martinsen. I would -- if I had to rank out the Netardus 2 forgetting the 3 at this time because of the [giant] hold restriction and the Welhausen wells, the 7 and 8, I'd say that they may be just a step below the Martinsen at this time, but I don't think it is a big step.

As I said, mid year we put about a million barrels equivalent on both the Martinsen and the Welhausen 2 and there was room to take it up even further, so there's probably a good reason how these things, why these things are acting fairly flat early on because of the natural fractures in the upper and the fractures you're inducing it just causes a much more efficient cleanup, and I think that's why is it explains how these things are flattish or even increasing over time. So, the Welhausen, I think it's Welhausen 7, is increasing as we speak and Netardus 2 continues to get better. But I realize that's a lot of words try to explain this, but if they are below the Martinsen and Welhausen, I don't think they're a lot below those two.

Okay. So still very strong wells. And typically how long does it take from initial pull back to clean those things up?

The Martinsen, because it's flat, I'd say it's still cleaning up even after five, six months, so that's a tough question to answer because these wells are making a lot of water. I'm talking about a couple thousand barrels of water a day. And you pump over, I don't know150,000 barrels of water in total or more, it will take some time, but they continue to improve. It's ever so slightly. You have to put it on a graph to see it, but it continues to get better over time. So, again, it's a tough question to answer but I would say it takes an appreciable amount of time to ultimately get these things cleaned up.

Understood. And then I know you are going to discuss 2015 capital budget in more detail mid December. Let me ask you a question in a little different way, see if I can get what I'm looking at, but when you had ramped up to 8 rigs, what kind of oil price did that assume? So was it sort of in that range of where we're at right now? And when you look at your 2015 capital budget decision, how does the weakness in oil price make your opinion differ from that level?

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

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

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

Understood. Thank you.

David Tameron of Wells Fargo.

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

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

Okay. Okay. No. That's helpful. Then what kind -- are you guys using resin coated sand or are you doing any tailing in or what exactly is your completion technique right now that you're most comfortable with or that you're seeing the best results from?

We're using a hybrid design that we will start off with slick water on our fluids that will grade over to a linear gel and then towards the end of the stage go to a cross-link gel. On the proppant side, once we get our pad pumped, we will start pumping hundred mesh and then go to white sand and then tail in with the last 50,000 or 60,000 pounds of resin coat. And the primary difference is in our three-string wells the sand or the proppant we're using is 3050 and in the two-string areas it's 2040.

What we have found is in the Upper Eagle Ford even in our three-string areas we're often able to get some 2040 away at the higher slurry density. So typically we would end up with maybe 3 pounds per gallon of final slurry density, but in the Upper Eagle Ford we're often ended up at 4 pound per gallon apparent or higher.

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

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

Okay.

That's sort of how we're going to do it.

Even that's helpful. I appreciate it. Thanks.

Okay, thank you.

Welles Fitzpatrick of Johnson Rice.

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

These Netardus wells are actually west if memory serves me correct. Not a lot west, but they're west. The GORs are somewhat lower because subsurface depth wise you would expect to be somewhat less as you go to the west. I think there's also some unknowns because of the cleanup issue. It would not be uncommon on something like this where your gas tax should be a higher GOR initially because it's easier to break through your water than what the oil would be, so I would not read a lot into the GOR at this time until we get more production history.

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

I did not but, John, do you know what they are? I can't remember.

Not off the top of my head -- 26 and 27.

Twenty-six, okay. Perfect. Thanks. And then just one last one. The lower per acre price, is that a function of you guys moving a little bit more towards areas that are perspective mostly for the upper or is that just a response to folks leasing lower for lower oil prices?

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

Okay, perfect. Thanks so much.

Kim Pacanovsky from Imperial Capital.

Good morning. Just wondering, what percent of your acreage that is prospective for the upper Eagle Ford would be due with the rest of the 2014 program, the 11 wells that are planned? Assuming they're all successful.

I'd say -- I can't give you an exact percentage. The only reason I can't is because that acreage we bought here we announced I think back in July. We need to get some wells drilled on it as you go to (inaudible) ease, but out of the 50% that John mentioned, I'd say probably 85% of that 50% would be de-risk with this program in the second half of this year, that would be an estimate.

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

They are, but as you go to the west into Gonzalez County, the potential of the upper deteriorates. So, it's primarily from the Gonzales Lavaca County line east and to the north. So everything in Lavaca County we think is prospective in the upper.

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

John, can you -- ?

Looking at our Cinco J Ranch is probably one of the best wells we've drilled, that was in Gonzales County. We IP'd at 2,600 Boe per day and out most of that was oil. That is actually in our Rock Creek Ranch area, what we call our Bozka acreage. That is going to be over on the western half. And then a little bit south of that we had two more, our L&J Lee units that each tested over 2,100 barrels of oil equivalent per day.

And then we had quite a few in the beer quad, the cosmos and the Porters, and then we had four more in what we call the zoo area, the leopard hunter in the upper part of prior Magnum Hunter Peach Creek acquisition that are named after various animals. So there was four there and then we had two more that were shallow wells that were drilled down in southwest Gonzales County that are not part of our contiguous acreage in the core of our acreage.

Are those hunt wells or near the hunt wells?

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

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

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

Got it. Okay. All right. Great. Okay. Thanks, guys.

All right thanks, Kim.

Gail Nicholson of KLR Group.

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

That's casing. We run a surface pipe down to roughly 3,500 feet which is 13 3/8. We run 9 5/8 to the [chock] if we drills in lower Eagle Ford. If we drill in upper Eagle Ford, it's actually a little bit shallower than the chock and then we run a 5 1/2 production pipe, so that's how we come up with the three-string terminology.

No, I'm sorry, three-string, so it's [52%] and 54% oil. What's the NGL and gas composition?

On the upper it's around 52% oil. I think the NGLs are around 25% and the rest of it would be residue gas.

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

I think it will be closer to the third quarter.

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

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

Okay, great. Thank you.

Adam Michael of, Miller Tabak.

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

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

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

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

Okay, that's helpful. Thanks, guys.

Richard Tullis of Capital One.

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

You always have some lower wells. We were talking with Kim about those couple wells in Culpepper down in the southwest part of Gonzales County. They have lower IPs, but the drilling completion costs are significantly less, so the economics are just as compelling but it just has a lower IP.

It also has a lower decline rate associated with that stuff down there. So, there are some shallower wells that did have some affect on lowering the IP rate per lateral foot. But, in general, we still think the economics are solid. Some of the wells we had to lower IPs or cheaper wells drilled on complete also.

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

Netardus 2 is making around 650 barrels day and almost $2 million and continues to increase as it cleans up. The Netardus 3 which had the giant hold restriction we've got to go back in and get it out in time is restricted at roughly 250 barrels a day and about 900 Mcf a day but is flat.

I think based on where their restriction is, that well would be as good if not better than the #2 well, but we got to go back in and get it out, we've been successful in doing that in other wells. There is no reason not to do it. Sometimes you're better off doing it when the pressure comes down somewhat on these wells for safety reasons and cost reasons, so we will do that at the appropriate point in time.

Okay. And then just lastly, what's the current outlook on potentially monetizing the granite wash assets? Are you guys just going to -- looks like you'll just retain those assets and produce them out.

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

That's all. Thanks a bunch.

All right, thank you.

Sean Sneeden of Oppenheimer.

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

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

Okay. Sure. Understand. Would it be still fair to say that you would want to -- I think you said previously you want to keep a minimum amount of liquidity and keep I think leverage in check. Would it be fair to say keeping leverage under three times is still a relative priority for you as you set your budget?

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

Okay. That's great. Thank you. If I can squeeze one more in. How do you guys -- you guys talked a little bit about buying back shares. How would you think about buying back bonds to the extent their trading below par?

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

Okay. Great. Thank you very much.

[Verju Burnachel] of Susquehanna.

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

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

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

They were 400 feet. Is that correct, John?

Yes.

So they are close.

Okay. Great. Thank you.

All right, thank you.

Philip Pennell with Mariner.

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

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

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

Exactly.

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

Three hundred -- was the question total number of wells?

Yes, net wells.

Just in Eagle Ford?

Just in the Eagle Ford.

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

Three hundred gross. Okay.

If you want to estimate the net, I'd take 75% of it or so.

Right. Okay. Great. Thanks, guys.

Okay, thank you.

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

If there were any people weren't able to ask questions for time restraints, I would encourage you to call Jim Dean and we can get those questions answered. But, lastly, I'd like to thank you for your support. As we said, we'll get back to you in the December/January timeframe about our revised CapEx and production guidance.

Even though, and I want to say again, even though we're rethinking our CapEx program for next year, again I want to reinforce that we have a very high quality Eagle Ford asset and our soul intent is to maximize our returns on the money invested, and enter this pricing environment which way be deteriorating further we feel that retaining a strong balance sheet is very, very important to a Company like Penn Virginia at this time. So, I'd like to say goodbye and have a great day. Thank you very much.

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