Penn Virginia Corporation
Q2 2013 Earnings Call Transcript

Published: 8 Aug 2013

[Operator:]

Good day, ladies and gentlemen, and welcome to the Penn Virginia Corporation Second Quarter 2013 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 call is being recorded. I would now like to turn the call over to Mr. Baird Whitehead, President and CEO. You may begin.

[Baird Whitehead:]

Thank you, Michelle, and good morning. I would like to welcome you to Penn Virginia’s second quarter 2013 conference call. I am joined today by various members of our team, including John Brooks, our Executive VP of Operations; Nancy Snyder, our Chief Administrative Officer; Steve Hartman, our CFO, and Jim Dean, our Vice President of Corporate Development. Prior to getting started, we would like to remind you that the language in our forward-looking statement sections of the press release as well as our Form 10-Q, which were both filed last night, will apply to our comments this morning. The obvious highlight of the second quarter was a significant $400 million acquisition we made of what we consider is a highly complementary Eagle Ford assets from Magnum Hunter. We have previously released the details associated with that acquisition, but has felt they were expanded Eagle Ford position that is currently 62,000 net acres and still increasing, which significantly changed the growth profile of this company over the next two years. To fund the acquisition, we successfully placed $775 million of 8.5% notes that are due in 2020. With these proceeds, we also regained $300 million of what’s 3.8% notes that we due in 2016. So right now, the earliest we have any long-term debt due is 2019 and that is $300 million of 7.25% notes. As a result, we now have a premiere for position, what we consider with improving well results. We also have a balance sheet and sufficient liquidity that will allow us to fund to see referred capital program. And at the same time, grow cash flow while instantaneously reducing our spend and improving our leverage ratio such that we continue to expect to be self-funding our capital program by the end of 2015 going into 2016. This is extremely important for us. In addition, we continue to add to our Eagle Ford position our backyard. We recently included in our press release that we added about 9,000 net acres to bring our current total of 62,000 net acres. These 9,000 net acres were added at a cost of only about $1,600 an acre. We are getting some questions as well, if you’re picking acreage up this cheaply, there must be limited potential on net acreage, and I can tell you that is totally incorrect. The reason we can pick this up so in expensively is due to the fact that we have grown to the point that we now have a fairly contiguous leasehold in this part of the trend and with this type size, it invites opportunities for that others cannot get. It only make sense for landowners knowing that they will get acreage soon or latter and get into the pipeline, which means they will start collecting royalty center. Getting royalty check motivates landowners to lease since the economics of royalties trump lease bonus payments. We have the rigs. We have the pipelines in place so the choice is pretty obvious for landowners. In addition on top of the 9,000 acres we have about another 4,000 acres that we have negotiated. We have not yet signed a lease on that over the next month or so we should be able to give leases signed. So that will be on top of the section to bringing us to about 66,000 net acres. So, we continue to ramp-up our acreage position. With additional acreage and further down spacing opportunities, we have increased our drilling inventories outlined in the press release from 645 locations to 750 locations. The 4,000 acres that I just mentioned that we should soon lease, we had another 30 to 40 locations on top of the 750. Therefore, we are getting pretty closed to 800 remaining locations, which puts us over a 10-year inventory what we consider a long run lead the real growth for Penn Virginia. Can we expand the number of locations further, sure we can but as we stated in the past, the 750 number is what we have geologically and engineering supported with a surface location and the bottom location on a map. What is also important to point out that the 750 number also includes a large number of 6,000 to 8,000 foot laterals whereas our previous inventory included primarily 4,000 to 5,000 foot laterals. Drilling longer laterals eliminates some locations, but of course ultimately improves the economics of those locations. Overtime in our probability lease, we could increase inventory by an estimated 10% through further down spacing. Most of that would occur in the western Gonzales County acreage also most of our locations are map then configure taken into account the shape of the drilling unit, the longer light of laterals and drilling wells in the northwest southeast directions which is typical configuration. Could we drill some shorter laterals or more north side or east west laterals to utilize more or all the unit an effort to our inventory we certainly can. But we think we need to continue to add locations over time after we test these ideas as well as other potential intervals on our acreage including the upper Eagle Ford, the Austin Chalk and Pearsall none of which are in the current inventory. As mentioned with an ongoing program similar 2013 we now have a drilling into that as a minimum of approximately 10 years and growing. Going to second half of 2013, you plan to drill 41 gross, 23.3 net wells, Eagle Ford alone bringing our 2013 estimated total to 69 gross and 42.3 net Eagle Ford wells. On top of this are the additional 16 gross wells drilled by Magnum Hunter and Hunt from January 1st through closing whose costs were included in the purchase price adjustment. This brings a total 2013 Eagle Ford program to 85 gross wells. Over the next few years, we expect to continue to drill approximately 75 to 80 gross wells per year in the Eagle Ford, assuming an ongoing six week program and expect that to provide the 30%, 40% production growth in oil. We are anticipating 67% increase in oil production in ‘13 as compared to 2012. The company wide we produced a total of approximately 70,500 barrels a day equivalent during the first half of this year, 19,200 barrels a day equivalent during the second quarter with the expectation to average about 21,600 barrels a day equivalent during the second half of this year. During the second quarter of 2013, we produced about 11,500 barrels a day equivalent from the Eagle Ford which includes little over two months of production from the Magnum Hunter assets. In the second half of this year, we expect to average approximately 14,300 barrels a day equivalent from Eagle Ford up to 16,500 barrels a day equivalent during 2014. Adjusting only well we expect to produce about 12,000 barrels a day during the second half of this year versus 8,050 barrels per day for the first half bringing the 2013 total to 3.8 million barrels which has already mentioned is about 67% increase year-over-year. In the second half of this year, quarterly production growth will be somewhat block year, due to the increased emphasis on pad drilling and the fact that our time from spud to turning line for instance on three well pad could be up to four months. We reported adjusted EBITDA during the second quarter of $83 million, which was the highest quarterly level since 2008 when we still had an active gas drilling program and gas prices of course much higher. The increase in adjusted EBITDA which was primarily attributable to the acquisition at the end of April as well as continued excellent well results including lower unit operating cost from our existing operations. Steve will discuss here shortly our 2013 adjusted EBITDA guidance of $310 million to $350 million and price about $93 million per quarter in the second half of 2013 or about 12% higher than the second quarter. So we believe our expected cash flow will become much more evident – cash flow growth will become much more evident over the next few quarters and will only escalate in the 2014 and in 2015. Our 2013 CapEx guidance is now $470 million to $510 million, which was increased by approximately $50 million from the previous guidance. Almost all of this increase was due to a step-up in our leasing activity in Eagle Ford. With the successful results of the upper Eagle Ford that we talked about in the first quarter, very successful lowering referred results in the Lavaca County along with the damages of the synergy size that I mentioned earlier with the Magnum Hunter acquisition, all of these resulted in new leasing opportunities for us. And as long as we continue to acquire acreage in our backyard at very attractive per acre cost we will continue to push this leasing effort. As a result of these expected increases in the cash flow and expected modest decreases in CapEx assuming the six week program going forward, a trend that we expect to continue in the ‘14 and ‘15 and beyond we continue to have a target and are committed to self-funding our capital program by late 2015 going into 2016. Even though, we have $300 million of financial liquidity to continue to fund our CapEx program, we also continue to explore various avenues to reduce indebtedness through the sale of non-core assets. Currently we have engaged an outside firm to explore the sale of our existing gas gathering along with the rush to construct an oil pipeline gathering system in our Eagle Ford. While it’s too early to say with the proceeds might be from this potential sale, we do think it’s a premium asset because of this long-term growth that hard to attract some solid interest. We expect this stack has been the market during the third quarter and assuming we received an attractive offer at the closed by the end of this year or early 2014. We continue to rationalize whether selling some gas assets just trying to make sense. Right now today, gas prices we would receive little value if any for the drilling and so it makes no sense to us to best to these assets right now. That said that we will continue to watch product pricing and possibly under a higher features market reconsider this position. Lastly I’ll provide an operational update and feel that we have a number of positive developments in discuss. First of all, recent drilling as you that estimate wells with an average IP of about 280 barrels a day equivalent and average 30-day rate of about 790 barrels a day equivalent, not including any NGLs through processing. In general, we think the higher rates can be attributed to the longer lateral lengths we have begun to drill, therefore, more frac stages as well as the fact that many of these wells were drilled in Lavaca County, where there are high reservoir pressures. We also believe that we are beginning to see the advantages associated with pad drilling and closer well spacing, which in all probability improves induced frac efficiencies, and therefore overall production rates. We currently have four operator rigs with two non-operator rigs drilling. One of these operator rigs is currently being enacted to be a walking rig for our pad drilling, which makes it more cost efficient minimizing any downtime between the time production casing is run and when the next well on that pad spuds. 14 of the most recent 22 wells were drilled off a six multi-well pad, generally 2 to 3 wells per pad. And majority of the results and initial production rates have been excellent. The closure spacing and the use of zipper fracs appear to be working well as I stated earlier. And there is another three wells, we just turned in line after completion, it’s called the Stag Hunter 1 and 2 and the Platypus Hunter well that they have only been on last one back a few days now and each one of those three wells are making almost a 1,000 barrels a day and continue to improve. So, in general, we think things are working very well on our drilling and completion program. In general, on the wells, the recent wells, we have drilled from these multi-well pads, the average IP has been about 14 barrels a day equivalent and an average 30-day rate of about 800 barrels a day with an effective spacing of between 45 and 70 acres. Going forward, since much of our legacy acreage is now held by production we will continue our development program more so with pad drilling and drilling on closure spacing. During the second quarter, we made an attempt to test another upward Eagle Ford interval in the western portion of Gonzales County acreage. As we discussed on our first quarter call, if you remember, we completed a well in Eastern Lavaca County acreage called the Fojtik that was a very good well. We wanted to test the western part of our acreage, but we have some drilling difficulties and drilling at interval. So, we opted to drill the lower Eagle Ford instead, but this does not change our plans of our enthusiasm for the potential of this interval. Since we have mapped this, the extent of this interval across our acreage and we’ll definitely make another attempt at the completion to confirm its potential. Just to remind everyone, if ultimately success with the drilling inventory in both Gonzales and Lavaca counties. And lastly as discussed in our earnings release, our focus going forward will be to reduce our Eagle Ford drilling and completion cost. We are transitioning right now to new pressure pumping providers, and we expect to save at least 25% on completion cost per frac stage beginning in the second half of this year. Also the move to more pad drilling provides additional cost and efficiency savings. Any follow-up or any more detail questions concerning our Eagle Ford operations I can get John Brooks too available to answer those questions during the Q&A. So, with that, I would like to turnover to Steve, so he can give you an update of our financial progress as well as our update of our guidance.

[Steve Hartman:]

Okay, thanks Baird and good morning every one. First thing I would like to note as you know we closed our acquisition of the Eagle Ford shale asset from Magnum Hunter during the second quarter on April 24. For accounting purposes, any activity, production revenue, expenses, capital spending, etcetera that occurred after the closing date is included in our second quarter numbers and 2013 guidance. Any activity that occurred prior to the closing date was recorded as a purchase price adjustment. And the purchase price adjustment isn’t finalized yet, we expect to have that done by the fourth quarter. Product revenues for the quarter were $109.7 million, or $62.78 per BOE, up 34% over the first quarter. The increase was driven by 43% increase in oil volumes offset by lower realized oil and NGL prices. Oil and NGL revenues were $94.2 million, which is 86% of product revenues. Our realized oil price was $101.23 per barrel, down from $105.28 realized in the first quarter. Including cash settlements from hedges, our realized oil price was $104.10 per barrel, down from $109.97 realized in the first quarter. We received $2.2 million in cash settlements from hedges during the quarter. And as a reminder, our hedge proceeds are not included in our reported revenue. They are reported in derivatives income. Operating expenses were 7% higher this quarter due primarily to the higher product volumes. This excludes $2.4 million of G&A expense related to the acquisition of the Magnum Hunter assets. On a per barrel basis, our adjusted operating expenses were down 12% at $16.68 per BOE compared to $19.06 in the first quarter. And again, on a unit basis, all categories of our operating expenses were lower this quarter. LOE was down 10% at $4.94 of BOE. Gathering, processing, and transportation expense was down 32% at $70. This includes the impact of a one-time charge recorded in the first quarter, but still a good number. Production and ad valorem taxes were 6.4% of product revenue, down from 7.2% in the first quarter, and cash G&A expense, not including the acquisition transaction cost I just mentioned was down 12% at $6.05 per BOE. We did add some G&A post-acquisition with a slightly higher employee headcount as you would expect with such a large acquisition, but this increase was more than offset by the higher production and cash flow, which gave us the lower per barrel cost. Our gross operating margin and non-GAAP measure, that’s generally defined as product revenues, less direct operating expenses increased 20% or $7.54 per BOE over last quarter. This gross operating margin improved from $39.29 to $46.09 per BOE. We are very excited about this metric and think it’s about the best in the business. Our Eagle Ford production had gross operating margin of over $70 a barrel without allocated G&A in the second quarter, and that’s what’s driving the dramatic improvement in the margin. So, as you can see as we continue to invest almost exclusively in the Eagle Ford play, our gross operating margin and our overall cash flow continues to increase. Adjusted EBITDAX for non-GAAP measure reconciled on page 10 of the release was $83.1 million, which is 38% higher than the $62.3 million reported last quarter. And as Baird mentioned, this is the highest quarterly adjusted EBITDAX we have had since 2008. Our loss attributable to common shareholders for the quarter, which includes the effect of deducting $1.7 million of preferred stock dividends, was $27.2 million or $0.43 per diluted share. This includes a $29.2 million loss on extinguishment of debt related to the refinancing of 10.38% notes. Adjusting for this one-time loss another customary adjustment shown on page 10 in the release, our adjusted net loss attributable to common shareholders was $10.9 million, or $0.17 per share. This is a $0.02 per share improvement over the first quarter. Capital expenditures for the quarter were $145 million, up from $96 million in the first quarter. Capital spending for the quarter was on target with our expectations given the larger drilling program post-acquisition. What we did not anticipate in our last guidance update was the opportunity to add leasehold in Lavaca County as Baird mentioned. So, that’s now included. And moving on to capital resources and liquidity, at quarter end we had $67 million outstanding on our credit facility and $19 million of cash on the balance sheet. We successfully raised our borrowing base and commitment in the spring bank re-determination from $276 million to $350 million. With the addition of borrowing base and including our letters of credit, we had $280 million of borrowing capacity and about $300 million of total liquidity. Our leverage is 3.5 times debt to adjusted EBITDAX, which is on pace for where we were expecting to be given the additional borrowing for the land ads. Pro forma adjusted EBITDAX for the trailing 12-month period was $329 million. Our permitted leverage for the credit facility is 4.5 times. So, we currently have full access to the revolver liquidity. Our next borrowing base re-determination is coming up in November. It’s very early in the process obviously, and we haven’t given the banks any information from mid-year yet, but we still feel good about yearend borrowing base being around $400 million. And moving on to hedges, we have been adding hedges to our crude oil portfolio through 2014 looking to protect $90 WTI and keeping upside where we can. We currently have 9,500 barrels a day of oil hedge for the remainder of 2013, which is about 75% of the midpoint of guidance at a weighted average floor of $94.59 per barrel. We have roughly half of our oil hedge for 2014 with a weighted average floor of $93.44 per barrel and our current hedge position is summarized on page 12 of the release. Looking at 2013 guidance update, which is detailed on page 11 of the release, our guidance hasn’t really changed materially as we continue to execute the plan we laid out for you after the acquisition. We are adjusting mostly for the exercise of prep rights by some of our legacy Eagle Ford acreage partners and the Magnum Hunter acquisition. Closing the acquisition a week earlier than we had originally anticipated more pad drilling versus single well drilling and the previously mentioned incremental land ads in Lavaca County. We are increasing production guidance slightly to 6.6 million to 7.5 million Boe. The production mix is shifting slightly more toward the gas due to higher GORs and the downdip Lavaca County wells. We still expect our oil and NGL percentage to be around 60% to 63% of total production. Oil production guidance is a little wider at 3.5 million to 4 million barrels and that’s due to moving toward more pad drilling which makes tying in wells to sales, a little bit more or less predictable. Production revenue was increased by $2 million to a range of $416 million to $471 million. This is assuming $90 WTI price and $3.70 Henry Hub natural gas price through the end of the year. This does not include hedges. We are still expecting 86% to 89% of our product revenues to come from oil and NGLs. We are expecting LOE to remain unchanged at $5.60 to $6 per BOE. We are raising our guidance on gathering processing and transportation slightly to the higher natural gas and NGL volumes. Oil transportation costs for Eagle Ford oil are not included in this expense item. That cost is netted out of revenue at an average rate of about $8 per barrel. We are decreasing our production and ad valorem tax estimate as we have been realizing some tax credits. Recurring cash G&A is revised slightly lower due to lower headcount than originally planned, a cash run rate of $10.5 million to $11 million per quarter is a good estimate. We added the acquisition transaction expense cost of $2.4 million, that’s non-recurring, but it is included in the guidance for total cash G&A. We expect non-cash exploration expense to be lower due to lower unproved property amortization. We are not changing our DD&A rates for the quarter. For adjusted EBITDAX we are tightening our range at $310 million to $350 million, but the mid-point is relatively unchanged. This includes cash settlements from hedges of about $12 million assuming a $90 oil price and $370 natural gas price for the second half of 2013. This is not a pro forma number for the acquisition. If you are going to use this number to model our leverage at year end, you will need to add about $26 million of pro forma adjusted EBITDAX to get an accurate number for our credit facility compliance. We should end the year at about 3.3 to 3.4 times leverage, and we expect leverage to continue to improve in 2014 ending the year at around 3 times, and that’s assuming no asset sales just organic growth. We expect adjusted EBITDAX would probably grow at around 25% per year over the next few years assuming the same type of capital program that we have been seeing in 2013. Our capital expenditures guidance is now $470 million to $510 million. The primary change as we mentioned previously is the addition of about $15 million for lease act. Finally, we added some new guidance this quarter. We are now guiding to yearend total debt of $1.21 billion to $1.25 billion. This implies the credit facility balance at year end of $135 million to $175 million. Under our current borrowing base commitment of $350 million, we would have yearend liquidity of about $175 million to $215 million, but if we achieve the $400 million borrowing base as we expect to, our year end liquidity would be about $225 million to $265 million. And Baird, that concludes our guidance review.

[Baird Whitehead:]

Alright, thanks Steve. Michele, at this time, we are ready to go in and take any questions please.

[Operator:]

(Operator Instructions) Our first question comes from Neal Dingmann of SunTrust. Your line is open.

[Neal Dingmann:]

Good morning guys. And Baird, nice quarter say Baird just wondering you continue to add, pickup this Eagle Ford acreage obviously at a very attractive price. Just wondering when you look at continued opportunities, I don’t know how much you are willing to say, just wondering what you have kind of for these low prices still for the remainder of this year and you continue to have more opportunities like that next year?

[Baird Whitehead:]

I think so. I mean, I am probably maybe it’s too aggressive to go, but I always wanted get to 100,000 acres in Eagle Ford in our backyard in total. So, with this 4,000 that we think we have committed, I guess, it’s 66. If we continue to add at that kind of clip, which I don’t think is overly aggressive over the next couple of years, is 100,000 doable, I certainly think it is. And I think we continue to do it at these kind of modest lease acquisition costs, I mean, there is acreage, there is falling off under primary term to other parties that opportunities arise. As I said earlier, there is open acreage that we continue to lease, because people know we can get the wells drilled and turned in line. So, I think we can – I mean I think we continue to add acreage, and ultimately, I would like to get to 100,000 acres in this general area.

[Neal Dingmann:]

Great answer. And then I was wondering I know a lot of guys continued to do different things as a completion techniques, adding more sand, tighter stages etcetera. Just wondering around was there something different number one around that Pilsner, I mean obviously that result sort of sticks out that you did on that? And then just wondering on the sort of a go-forward basis, are you doing some of these newer techniques, you mean, adding more sand, tighter spacing that you would have confidence that these results will continue to improve a bit?

[Baird Whitehead:]

Well, I mean, geology, I’ll just add bearing in results. John, I think probably you got to go ahead and summarize and explain what we are doing on the completion front right now, and how we continue to tweak? Thanks.

[John Brooks:]

Sure. Specifically, on the Pilsner, that was a 7,000 foot lateral, but 29 stages. So, the additional length certainly helps, the completion design is continuously being reviewed and evolved. And we are right now at a 250 foot stage length than I think that we will probably park it there for a while. On the actual sand amounts, we have historically been shooting for about ₤1000 per foot of lateral. And we are targeting now at around ₤1,200. So, we are trying to increase that sand count by about 20%. We have discontinued the use of the ceramic and gone with a raw resin coat. And it’s had the advantage of lowering some costs, we tail in with it. It also tends to hold your profit pack in place. So, when we clean the wells out just are flowing back we are seeing a lot less sand on flow back. And so we are leaving more sand in the formation, which gives us a better conduit from the reservoir into the wellbore. And I think the rates that we have seen are reflecting the increased effectiveness of that technique.

[Neal Dingmann:]

That’s great color, John. And then Baird, just one last one very quick just on you are quite in the management comments on the press release, where you mentioned expectations of self-funding by the end of ‘15. I am just wondering, I mean, either commodity prices or just sort of expenses as a services etcetera kind what not, not in detail, but just sort of general overall assumptions you are all making with that expectation?

[Baird Whitehead:]

I will let Steve get in and answer that Neal.

[Steve Hartman:]

Hi, Neal.

[Neal Dingmann:]

Hi, Steve.

[Steve Hartman:]

For commodity pricing, we are assuming $90 flat for WTI and natural gas increasing slightly $4 for ‘14, $4.25 for ‘15, but as you know, that’s not a big driver of our results, so it doesn’t really matter. LOE prices we are assuming just a slight increase for inflation, but relatively flat and then well costs we are expecting that to be relatively flat too. So, we would expect that, that would be right where we have been saying that it’s going to be.

[Neal Dingmann:]

So, Steve, it’s hard to say that if you are able to continue to peel off a little bit more well cost that, that month or the timing could be even a little bit before that?

[Steve Hartman:]

That’s correct. And asset sales, that assumes no asset sales, that’s just organic growth.

[Neal Dingmann:]

Great, great point. Thank you all. Nice quarter.

[Steve Hartman:]

Thanks, Neal.

[Operator:]

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

[Brian Corales:]

Good morning guys.

[Baird Whitehead:]

Hey Brian.

[Brian Corales:]

And you all talked about the cost declining $2 million I guess it’s mostly the completion side, one, can you tell about what the average well cost is today, and then is that $2 million was that all just completion cost with contracts or was part of that efficiencies is well, and can you see that going lower as you start pad drilling?

[Baird Whitehead:]

Hey, John, go ahead and take that question please.

[John Brooks:]

Sure. A big part of that has been our reduction and the completion cost due to the rollover of some older contracts, but the material costs have gone down as well, the proponent in the GOR cost have come down as well. So, we do expect that to continue decline. We got two types of wells we drilled basically, a two-string well and a three-string well. And the three string wells are what you have heard us talk about historically in our Shiner area, where we go deeper, I have to set intermediate casing for the ₤15 environment. In that type of well scenario, we are talking in the $8.5 and $9.5 or $8 million to $9 million on our total well cost range. In the Gonzales County, where we just had surface casing and drilled TD without intermediate, we’re looking at $7 million to $8 million cost and the range there is really a function of how long these laterals are. We are seeing our average laterally really grown, historically we had been in the 4,000 to 5,000 foot, now we are averaging going forward over 7,000 foot for the remainder of the year. So, while the first stage cost that come down dramatically probably is around about $100,000 of stage. We are adding more stages. So that will continue to attack the cost item that primarily to the pad drilling in some of the things that we’ve been able to do there is going and preset our surface casing or smaller rigs and then get our big rigs on it and we recently had one three well pad where we drill three wells to the 1,600 foot TD. We did all three of those wells in the 30-day period. So, it gives you all sorts of completion efficiencies in drilling efficiencies, but also a lot of well cost there is couple of those wells where we beat the AFE on the drilling side by about $1 million so couple that with the completion savings and you can see where that $2 million comes from.

[Brian Corales:]

That’s very helpful and one more kind of same tune, if you are increasing – lateral increasing number of stages, can we assume that EURs are going to drift higher?

[Baird Whitehead:]

Tom we can – we’re going to restrict to the tight curve we have for now and absorb that overtime, but I think that’s not an unreasonable expectation.

[Brian Corales:]

Okay. Thank you.

[Baird Whitehead:]

It’s not only because of frac, but as we continue to be more of the different fracs there is case we made, your frac job in general is a much more efficient whereas you tend to shadow these reservoirs more so than a single well by itself. So, not only is there a probably ultimate reserve increase in lateral length, but because you give more rock expose to the frac that you’ve induced which should ultimately improve your ultimate also.

[Brian Corales:]

Thanks guys.

[Baird Whitehead:]

Okay, thank you.

[Operator:]

Our next question comes from Welles Fitzpatrick of Johnson Rice. Your line is open.

[Welles Fitzpatrick:]

Good morning, a follow-up I guess to Brian’s first question, the CapEx that you put out this morning is there a less items or is that include the full impact of the near completions contract.

[Baird Whitehead:]

Yes, it does.

[Welles Fitzpatrick:]

Okay and then only initial upper Eagle Ford well, how is that holding up relative to, I believe you put a 500,000 EUR where is that holding that group?

[Baird Whitehead:]

It’s drop somewhat well at this time it looks like it’s probably a 350,000 ultimate kind of well that’s be an equivalent. I think what we need to, we need to drill a pad of upper Eagle Ford wells that will give it improved efficiencies on the frac side that we just discussed and in test at that way, but at end of the day that type well in the (fire stick) is still economical, number one, number two, I think we do better than that and number three we’ve got this interval this upper Eagle Ford mapped across our acreage and there are many areas on our acres we continue to exploit this upper Eagle Ford so, I think the (inaudible) lot at this time, but the we are on first well is an okay well.

[Welles Fitzpatrick:]

And what the additional mapping, any update is kind of one-third of your acreage seen perspective?

[Baird Whitehead:]

I think the number still holds through right because we have never planned inventory how much of the acres perspective versus how much we have, but I think the one-third probably still fairly accurate.

[Welles Fitzpatrick:]

That’s great, that’s all I have. Congrats on the quarter, thanks.

[Baird Whitehead:]

Alright, thanks.

[Operator:]

(Operator Instructions) Our next question comes from Biju Perincheril of Jefferies. Your line is open.

[Biju Perincheril:]

Hey, good morning, couple of questions on the – on your well count in the Eagle Ford, can you talk about what is sort of the title spacing seemed in there the distance between laterals.

[Baird Whitehead:]

I’ll let Steve to answer that question please.

[Steve Hartman:]

Sure, we’ve successfully tested on I think at least three different pads down spacing down to 400 foot between the laterals and that seems to be working very well as far as the well count throughout the entire leasehold it will vary between 400 feet where we can fit in some of it’s going to be 500 foot because the initial wells we drilled on a 1200 foot spacing or 1000 foot spacing so when we down space that the most logical since is to test the 500 first. So, we’ve got some upside in some of the areas where we’ve got the 500 foot, but we’ll drill the 400 foot where we can in some of our less prudent acreage where we have fewer penetrations and think we’ve guided down to 700 foot so we still got some room to run in the southwest part of our acreage.

[Biju Perincheril:]

Okay and in the southwest part, you haven’t tested, you haven’t actually drilled wells on the time spacing that’s alright.

[Steve Hartman:]

The 700 foot is the tightest that we’ve drilled in the southwest part of it and we are currently fracking of three well pad that is about 60% complete that will test the 750 spacing in the southwest part of the acreage.

[Biju Perincheril:]

Okay, thanks. And then also are you including any upper Eagle Ford locations in that…?

[Steve Hartman:]

No.

[Biju Perincheril:]

Okay and then question on guidance, the I think it’s clear wide the all number you take down the lower end, but what’s driving the uptake in NGL and gas guidance is that some you said for us are Granite Wash holding up better or?

[Baird Whitehead:]

It disappeared, the reason being as you got to the eastern Lavaca County in those are some of the gas rates alone, the GOR is increasing as we go to the east on the farm acreage I think the highest we have seen is may be 2,500 to 3,000 standard cubic foot per barrel so with that we’ve just the type curve for some of these eastern Lavaca County wells and because they are still very did wells, but the gas, the proportion amount of gas has increased on those wells.

[Biju Perincheril:]

Okay so it’s all driven by Eagle Ford mix.

[Steve Hartman:]

It is all we referred, yes.

[Biju Perincheril:]

Okay, got it, thank you.

[Operator:]

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

[Adam Leight:]

Hi, good morning everybody.

[Baird Whitehead:]

Hi, Adam.

[Adam Leight:]

I think you just answered part of this, but was going to ask on the higher gas components in the more recent Eagle Ford wells if that’s more function of geography or geology or something else completion technique.

[Baird Whitehead:]

No, it’s more of a function of geology as you got the east, you go deeper, it gets deeper so because of these shale resource plays the gas components tends to get higher but exactly geology.

[Adam Leight:]

So with the acreage you are adding is the – that could continue to move towards the higher gas proportion.

[Baird Whitehead:]

There is some acreages we are because of our success on the eastern part of our Lavaca County acreage, some of the acreages we are adding is adjacent to that so you expect GORs to be higher, we have adjusted our type curves in this most recent forecast, which cost the adjustment in our guidance because of that, but we are also acquiring acreage up whereas GOR would be even more so in the 500 to 1000 standard cubic foot per barrel which is pretty typical on some of the higher volatile oil stuff so, it’s a mix bag as far as where acreage have been acquired.

[Adam Leight:]

Okay, that’s great, thanks and on the completion contract, could you change contractors or did you just get a better deal with your existing provider.

[Baird Whitehead:]

We changed.

[Adam Leight:]

Okay.

[Baird Whitehead:]

We have two service providers right now.

[Adam Leight:]

And can you give us a sense of how much is pricing difference versus different mix of ingredients and different stages how much offset by the stage count.

[Baird Whitehead:]

John why don’t you try and answer that question please.

[John Brooks:]

Okay I would say probably 75% of the cost savings is going to be to more favorable pricing. The rest of this cost savings is come from the design side or we’ve discontinued the use of ceramic and gone to a resin coat tail end with white sand and hard mesh mix in the actual design, so the 75% of that probably due to more favorable contraction, 25% of that due to compliance design.

[Adam Leight:]

Okay, great and just how many assumptions you have got LOE current pumping up compared to what you recorded in the second quarter is that is there reason for that?

[Baird Whitehead:]

On a barrel basis it’s not the same, so it’s just higher volumes.

[Adam Leight:]

In fact you’re going from 4.94 to 6?

[Baird Whitehead:]

Sorry, I thought you’re talking about from first quarter guidance to second quarter guidance, I apologize. It will just be the – a change in the chemical mix for the most part. We have some more chemical treating costs as we add wells into the Eagle Ford we have to do some treating and that’s generally the cost.

[John Brooks:]

We’ve had to increase these two scavenger chemicals and some treatment chemicals. We also because of these ESPs that we inherited from Magnum Hunter which is a different kind of artificial lift we will continue with that effort or even some of the new wells because we own them, so as we pull the mud and put (inaudible) in some cases we will take those have them refurbished and run them back in. There are advantages to using ESP, so we will continue with that effort because we own some of these, but in general it was primarily chemical and ESP cost.

[Adam Leight:]

Doing that same diagnosis that’s all. On the asset sales I get it on the gas assets and if I missed it I apologize did you mention anything on midstream side?

[Baird Whitehead:]

Yeah, we have an effort in place right now we have outside firm who is – we have engaged to attempt to sell our gas gathering and right to lay and all gathering system. The all gathering is a very valuable component to the overall gathering value in Eagle Ford because as our volumes grow on both the gas and the oil side. So, if we like the number which we should know by the fourth quarter or late fourth quarter we will proceed, if not we won’t proceed, we are not going to give it away.

[Adam Leight:]

And can you give me a sense of how much value is in borrowing base for that or the anticipated borrowing…?

[Baird Whitehead:]

There is no value in the borrowing base for midstream, so we would expect to take no borrowing base adjustment for that.

[Adam Leight:]

Okay, how about the gas assets?

[Baird Whitehead:]

Same nothing in the borrowing base for the assets for say.

[John Brooks:]

Or again I think we’re saying the gas, if we saw some gas asset reserve there would be borrowing base.

[Baird Whitehead:]

There they would they would probably about $40 million adjustments for either the Granite Wash or the Selma Chalk roughly.

[Adam Leight:]

Okay, that’s great. Thanks

[John Brooks:]

Okay thank you

[Operator:]

Our next question comes from (inaudible) of MLV Company. Your line is open.

[Unidentified Analyst:]

Hi guys I want to know as you down space and are you seeing any frac interference or do you plan to run any micro seismic or is micro seismic run already?

[Baird Whitehead:]

John why don’t you answer that question please.

[John Brooks:]

Okay on the micro seismic there are some additional things we would like to do on the technical side, but we need to do them all together instead of piece meal we want to look at the micro seismic along with some additional radioactive tracing and production logging in conjunction with pads where we can get the most benefit from that. That will probably be a 2014 (afterwards) I think our drilling schedule for 2013 is fairly firmed up the remainder of the year, so that will probably fall in the 2014 budget. On the frac interference question, we do see some and it’s generally a positive thing that’s kind of the idea is to break up the rock and mobilize more liquids and gas to surface, so we have seen that and we hope to continue to see that.

[Unidentified Analyst:]

All right it sounds good. Most of my other questions have been answered. Thank you guys

[Baird Whitehead:]

Alright. Thank you.

[Operator:]

Our next question comes from David Snow of Energy Equities Incorporated. Your line is open.

[Baird Whitehead:]

Hey David.

[David Snow:]

Hi just as ballpark what do you think the comps would guess you might be able to get for the gas gathering?

[Baird Whitehead:]

Well for the gas gathering and the rest oil gathering system it could be worth anywhere from $75 million to $100 million.

[David Snow:]

That’s not enough to totally change your debt picture but it would be a little start.

[Baird Whitehead:]

And it’s something we don’t gain any value for, so it wouldn’t help personally you are right, but it does help.

[David Snow:]

And at this point you see the need to bolster your balance sheet whether it’s more equity as you look at the opportunities for picking up more acreage on here and then Eagle Ford?

[Baird Whitehead:]

No.

[David Snow:]

No.

[Baird Whitehead:]

We feel with the CapEx program we have over the next couple of years a six week program a fairly aggressive leasing effort in the Eagle Ford and the growth of our production and cash flow as a result of that program we would not need to go to the equity market to fund this. So, everything we have right now our plans are all build on organic growth and organic improvement in the balance sheet. And again I will say it for the 10th time and we will continue to say that is our – we are committed to get this done here by end of ‘15 or ‘16.

[David Snow:]

And then this last after relying for some interference on down spacing have you factored that into your tight curve you are large now?

[Baird Whitehead:]

Yes I mean that it will be there are continued adjustments as John said interference is not necessarily that. In fact we think it’s a positive and as we drill these longer laterals and get the shattering effect because of the zipper fracs and the closer spacing, we think over time we should be able adjust those tight curves up. But we are going to take wait and see attitude in order to do that of course before we make those kind of adjustments to tight curves.

[David Snow:]

What is your current EUR?

[Baird Whitehead:]

Well, we use roughly 200,000 barrels for equivalent for Gonzales and 500,000 for Lavaca County.

[David Snow:]

Great. Thank you very much.

[Baird Whitehead:]

Alright thanks David.

[Operator:]

Our last question comes from (inaudible) Southwest Securities. Your line is open.

[Unidentified Analyst:]

I appreciate, good quarter. My question involves when tighter laterals are closer in if there are compromises to existing wells nearby closer frac clogging up existing, is it economically feasible to go and rework existing or re-clean out to make sure that top lines didn’t…?

[Baird Whitehead:]

Well, I think maybe a better way to ask that question when we see interference if we have any existing well and we come back that question, when we see interference with the existing well that well typically we will shut it in before number one we will shut that well and some period of time before we start fracking any offset wells which you see is an increase production rate once you turn that existing well back in line there does not appear to be any long-term effects negative effects on that well because of that. In fact in some case because of the communication we actually see the production go up on that existing well because now because of the improved frac efficiency because of the offset wells you drilled to it, it just is a better conduit as John Brooks said earlier. So, as far as maybe what your question was did we thought about going back refracking some of these existing wells, at this time no. I guess somewhat mechanically operationally complicated in order to do that. It has to do with recourse tubing or through tubing and try to isolate the existing hubs and clusters which gets dicey you probably have to isolate segment and probably see the lateral was set up and try to do it overall and try to refrack. But something we would like to try to do at some point always don’t think we need to do it right now but it is something we will probably try to do over time.

[Unidentified Analyst:]

Thank you.

[Baird Whitehead:]

Thank you.

[Operator:]

We have a follow-up question David Snow of Energy Equities Incorporated. Your line is open.

[David Snow:]

Yes for those new wells in Gonzales and Lavaca what would be the percentage breakdowns of oil, NGLs and gas for each of those?

[Baird Whitehead:]

Memory serves me correct it’s about 85% oil, 10% NGLs and about 5% or 6% residue gas. If you go to Lavaca County, I think the oil maybe a little bit less, the NGLs maybe a little bit less, and the residue gas is a little bit higher, but it’s not materially different.

[David Snow:]

And the drilling cost is about what for the two counties again?

[Baird Whitehead:]

Lavaca County is typically about $1 million higher because of the (inaudible).

[David Snow:]

So, it’s about $7.5 million and $8.5 million or what was it?

[Baird Whitehead:]

I think John has said earlier is $8 million to $9 million for Lavaca County and $7 million to $8 million for Gonzales County depending on later length.

[David Snow:]

Okay. And then what’s the royalty there?

[Baird Whitehead:]

It’s usually 25%.

[David Snow:]

Great, terrific. Thank you very much.

[Baird Whitehead:]

Alright, thank you.

[Operator:]

I am showing no further questions. I would now like to turn the call back over to Mr. Baird Whitehead for any further remarks.

[Baird Whitehead:]

Well, thank you very much. We appreciate you listening in. One thing I forgot to do was to congratulate our Penn Virginia team on integrating the Magnum Hunter assets. It’s gone very smooth. Operationally, we are up and running and have things integrated. So, from that standpoint, our employees have done a fantastic job. We have got a good position at Eagle Ford right now. I would argue if you look at our 62,000 acres that we continue to grow and look at it on a map it’s a fairly large bull’s eye right now. We have got a large number of things to do. It’s going to give us some significant production growth and EBITDAX growth over the next couple of years. And again, I will say I guess for the 11th time now, our plan is to be self-funding that CapEx program in the late ‘15 early ‘16. And again, I can tell you we are committed to this goal over the next couple of years. So, with that, thank you very much.

[Operator:]

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