Ranger Oil Corp (ROCC) 2013 Q2 法說會逐字稿

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.

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 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 the highly complimentary Eagle Ford assets from Magnum Hunter. We have previously released the details associated with that acquisition, but it's felt that our expanded Eagle Ford position that is currently 62,000 net acres and still increasing will significantly change the growth profile of this Company over the next few years. To fund the acquisition we successfully placed $775 million of 8.5% notes that are due in 2020. With these proceeds, we also redeemed $300 million of our 10.375% notes that were 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 Eagle Ford position, what we consider with improving well results. We also have a balance sheet and sufficient liquidity to allow us to fund this Eagle Ford capital program and at the same time, grow cash flow while simultaneously reducing our out 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 '16. This is extremely important for us. In addition, we continue to add to our Eagle Ford position in our backyard.

We recently, and included in our press release, that we added about 9,000 net acres to bring our current total to 62,000 net acres. These 9,000 net acres were added at a cost of only about $1,600 an acre. We always get some questions well, if you're picking acreage up this cheaply, there must be limited potential on that 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 continuous leasehold in this part of the trend, and with this type of size, it invites opportunities for us that others cannot get. It only makes sense for land owners, knowing that they will get their acreage drilled sooner than later and get it into the pipeline, which means they will start collecting royalty sooner.

Getting royalty checks motivates land owners 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 land owners. In addition, on top of the 9,000 acres, we have about another 4,000 acres that we have negotiated that we have not yet signed a lease on, that over the next month or so we should be able to get leases signed. So that will be on top of the 62, bringing us to about 66,000 net acres, so we continue to ramp up our acreage position.

With this additional acreage and further down spacing opportunities, we have increased our drilling inventory as outlined in the press release from 645 locations to 750 locations. The 4,000 acres that I just mentioned that we should soon lease will add another 30 to 40 locations on top of the 750. Therefore, we're getting pretty close to 800 remaining locations, which puts us over a 10 year inventory. What we consider a long runway for oil growth for Penn Virginia. Can we expand a number of locations further? Sure, we can. But as we have stated in the past, the 750 number is what we have geologically and engineering supported with a surface location and a bottom location on a map.

What is also important to point out, that the 750 number also includes a large number as 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. Over time, in all probability, we could increase inventory by an estimated 10% through further down spacing. Most of that would occur in our western our Gonzales County acreage. Also, most of our locations on our map have been configured, taking into account the shape of the drilling unit, the longer length of our laterals and drilling the wells in a northwest-southeast direction, which is typical configuration.

Could we drill some shorter laterals for more north-sourth or east-west laterals to utilize more or all of the unit and add further 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 size similar to 2013, we now have a drilling inventory that is a minimum of approximately 10 years and growing.

During the second half of 2013, we plan to drill 41 gross, 23.3 net wells in 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 1 through closing, whose costs were included in the purchase price adjustment. This brings the 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 6 rig program and expect that to provide a 30% to 40% production growth in oil. We are anticipating a 67% increase in oil production in '13, as compared to 2012.

Company wide, we produced a total of approximately 17,500 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 a 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 the Eagle Ford, and up to 16,500 barrels a day equivalent during 2014.

Addressing [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, as already mentioned, is about a 67% increase year over year. In the second half of this year quarterly production growth will be somewhat blockier due to the increased emphasis on pad drilling, and the fact that our time from spud to turning line, for instance on a three well pad, could be up to four months.

We reported adjusted EBITDAX during in 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 were much higher. The increase in adjusted EBITDAX was primarily attributable to the acquisition at the end of April, as well as continued excellent well results including lower unit operating costs from our existing operations. As Steve will discuss here shortly, our 2013 adjusted EBITDAX guidance of $310 million to $350 million implies about a $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 into 2014 and into 2015.

Our 2013 CapEx guidance is now $470 million to $510 million, which was increased by approximately $15 million from the previous guidance. Almost all 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 lower Eagle Ford results in Lavaca County, along with advantages of the synergy of size that I mentioned earlier with the Magnum Hunter acquisition, all have these resulted in new leasing opportunities for us. And as long as we can 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 cash flow, an expected modest decreases in CapEx, assuming a six rig program going forward, a trend that we expect to continue into '14, '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 rights to construct an oil pipeline gathering system in our Eagle Ford.

While it's too early to say what the proceeds might be from this potential sale, we do think it's a premium asset because of it's long term growth that ought to attract some solid interest. We expect this package to be in the market during the third quarter, and assuming we receive an attractive offer, have it close by the end of this year, or early 2014. We continue to rationalize whether selling some of our gassier assets at this time makes sense. Right now at today's gas prices, we would receive little value if any for the drilling inventory, so it makes no sense to us to divest these assets right now. Having said that, we will continue to watch product pricing and possibly under a higher futures market, reconsider this position.

Lastly, I'll provide an operational update and feel that we have a number of positive developments to discuss. First of all, recent drilling has yielded excellent wells with an average IP of about 1,280 barrels a day, equivalent and average 30 day rate of about 790 barrels a day equivalent, not including any NGL through processing. In general, we think the higher rates can be attributed to the longer lateral lengths that we have begun to drill, therefore, more frac stages, as well as the fact that many of these wells we're drilling in Lavaca County where there are higher reservoir pressures.

We also believe that we're seeing the beginning -- 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 outfitted to be a walking rig for our pad drilling, which makes it more cost efficient, minimizing any down time 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 6 multi-well pad, generally 2 to 3 wells per pad, and the majority of the results and initial production rates have been excellent. The closer spacing and the use of zipper fracs appear to be working well, as I stated earlier. There's another three wells we just turned in line after completion, called the Stag Hunter 1 and 2, and the Platypus Hunter well that they have only been on line for back a few days now, and each one of those three wells are making 1,000 barrels a day and continue to improve. 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 1,400 barrels a day equivalent, and 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 closer spacing.

During the second quarter, we made an attempt to test another upper Eagle Ford interval in the western portion of our 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 in drilling that 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 will definitely make another attempt at a completion to confirm it's potential. Just to remind everyone, if ultimately successful, this adds further to our drilling inventory in both Gonzales and Lavaca Counties.

Lastly, as discussed in our earnings release, our focus going forward will be to reduce our Eagle Ford drilling and completion costs. We are transitioning right now to new pressure pumping providers, and we expect to save at least 25% on completion costs per frac stage beginning in the second half of this year. Also, the move to more pad drilling provides additional costs and efficiency savings. Any follow-up or anymore detailed questions concerning our Eagle Ford operations, I can get John Brooks to help answer those questions during the Q&A. So with that, I'd like to turn it over to Steve so he can give you an update of our financial progress, as well as our update of our guidance.

Thanks, Baird, and good morning, everyone. First thing I'd like to note, as you know, we closed our acquisition of the Eagle Ford Shale assets for Magnum Hunter during the second quarter on April 24. For accounting purposes, any activity, production revenue, expenses, capital spending, et cetera, 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 a 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 per BOE in the first quarter. Again, on a unit basis, all categories of our operating expenses were lower this quarter, LOE was down 10% at $4.94 a BOE, gathering, processing and transportation expense was down 32% at $1.70. 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 costs 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 in cash flow which gave us the lower per barrel cost.

Our gross operating margin, a non-GAAP measure that is 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're 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. 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, a 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've 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 our 10.375% notes. Adjusting for this one time loss and other customary adjustments shown on Page 10 of 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 is now included.

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 redetermination from $276 million to $350 million. With the additional 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 adds. 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 redetermination 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 year end borrowing base being around $400 million.

Moving on to hedges, we've 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 hedged for the remainder of 2013, which is about 75% of the midpoint of guidance at a weighted average floor of $94.69 per barrel. We have roughly half of our oil hedged for 2014 with the 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 [preference] 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 adds 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 towards the gas due to higher GORs, and the down dip 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 is 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 for 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're expecting LOE to remain unchanged at $5.60 to $6 per BOE.

We are raising our guidance on gathering, processing and transportation slightly due 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 ad valorem tax estimate as we've 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 rate for the quarter.

For adjusted EBITDAX, we are tightening our range at $310 million to $350 million, but the midpoint is relatively unchanged. This includes cash settlements from hedges of about $12 million, assuming $90 oil price and $3.70 natural gas price for the second half of 2013. This is not a pro forma number for the acquisition. If you're going to use this number to model our leverage at year end, you'll 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 will probably grow at around 25% per year over the next few years, assuming the same type of capital program that we've 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 per lease add. Finally we added some new guidance to this quarter. We are now guiding to year end total debt of $1.21 billion to $1.25 billion. This implies a credit facility balance at year end of $135 million to $175 million. Under our current borrowing base commitment of $350 million, we would have year end 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.

Thanks, Steve. Michelle, at this time, we're ready to take any questions, please.

(Operator Instructions)

Neal Dingmann, SunTrust.

Baird, nice quarter. Baird, you continue to pick up 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're willing to say -- just wonder what you have for these low prices still for the remainder of this year, and do you continue to have more opportunities like that next year?

Neal, I think so. I'm probably -- maybe it's too aggressive a goal, but I always wanted to get to 100,000 acres in Eagle Ford in our backyard in total. So with this 4,000 that we think we have committed, that gets us to 66,000. 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 can continue to do it at these kind of modest lease acquisition costs.

There's acreage that's fallen off under primary term to other parties that opportunities arise. As I said earlier, there's open acreage that we continue to lease because people know we can get the wells drilled and turned in line. I think we can. I think when you continue to add acreage, and ultimately, I would like to get to 100,000 acres in this general area.

Okay, great answer. I was wondering -- I know a lot of guys continue to do different things with the completion techniques by adding more sand, the tighter stages, et cetera. I'm just wondering around -- was there something different, number one, around that Pilsner? Obviously, that result sticks out that you did on that. And then just wondering on a go-forward basis, are you doing some of these newer techniques? Are you adding more sand, tighter spacing, that you'd have confidence that these results will continue to improve a bit?

Geology always has some varying results. John, I think probably you ought to go ahead and summarize and explain what we're doing on the completion front right now, and how we continue to tweak things.

Sure. Specifically, on the Pilsner, that was a 7,000-foot lateral with 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, and I think we'll probably park it there for a while. On the actual sand amounts, we historically have been shooting for about 1,000 pounds per foot of lateral, and we're targeting now around 1,200 pounds, so we're trying to increase that sand count by about 20%.

We have discontinued the use of the ceramic, and gone with a resin coat, and it's had the advantage of lowering some costs -- we tail in with it. It also tends to hold your proppant pack in place, so when we clean the wells out to start flowing them back, we're 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 well bore, and I think the rates that we have seen are reflecting the increased effectiveness of that technique.

That's great color, John. And then, Baird, just one last one very quick. Just on -- in the management comments on the press release where you mentioned the expectation of self funding by the end of '15, I'm just wondering, either commodity prices or just sort of expenses, services, et cetera, what -- not in detail, but just general overall assumptions you are making with that expectation.

How about Steve can go ahead and answer that, Neal.

Neal, for commodity pricing, we are assuming $90 flat for WTI, and natural gas increases 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're assuming just a slight increase for inflation, but relatively flat, and then well costs we're expecting that to be relatively flat, too. We would expect that that would be right where we've been saying that it's going to be.

So, Steve, it's sort of to say that if you're able to continue to peel off a little bit more in well cost that that month or the timing could be even a little bit before that?

That's correct. And asset sales. That assumes no asset sales; that's just organic growth.

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

Thanks, Neal.

Brian Corales, Howard Weil.

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

John, go ahead and take that question, please.

Sure. A big part of that has been the reduction in the completion costs due to the rollover of some older contracts. But the material cost had gone down as well. The proppant and the guar costs have come down as well. So we do expect that to continue to climb.

We have two types of wells we drill basically -- a two-string well and a three-string well. And the three-string wells are what you've heard us talk about historically in our Shiner area, where we go deeper and have to set intermediate casing for the 15-pound environment. In that type of well scenario, we're talking in the $8.5 million to $9.5 million, or $8 million to $9 million total well cost range. In the Gonzales County, where we just set surface casing, and drilled to TD without intermediate, we're looking at a $7 million to $8 million cost. And the range there is really a function of how long these laterals are.

We're seeing our average lateral length really grow. Historically, we had been in the 4,000 to 5,000 foot, and now we're averaging, going forward, over 7,000 foot for the remainder of the year. So, while the per-stage costs had come down dramatically, probably around about $100,000 a stage, we're adding more stages. So that -- we will continue to attack the cost side of it primarily through the pad drilling.

Some of the things that we've been able to do there is go in and preset our surface casing with smaller rigs, and then get our bigger rigs on it. And we recently had one three-well pad where we drilled three wells to a 16,000-foot TD. We did all three of those wells in a 30-day period. It gives you all sorts of completion efficiencies and drilling efficiencies, but also a lot of well costs. There was a 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.

Very helpful. One more on the same tune -- if you're increasing lateral, or increasing number of stages, can we assume that EURs are going to drift higher?

I think over time we can -- we're going to stick to the type curve we have for now, and observe that over time, but I think that's not an unreasonable expectation.

Okay. Thank you.

Brian, it's not only because of frac [length], but as we continue to do more of these zipper fracs, there's a case to be made -- your frac job in general is much more efficient, whereas you tend to shatter these reservoirs more so than a single well [piped] by itself. So not only is there probably ultimate reserve increase if you have a lateral limit, but because you just get more rock exposed to the frac that you've induced, which should ultimately improve your ultimates also.

Thanks, guys.

Welles Fitzpatrick, Johnson Rice.

Good morning. Follow up to Brian's first question -- the CapEx that you put out this morning -- or last night, I'm sorry -- does that include the full impact of the new completions contract?

Yes, it does.

Okay. On the initial upper Eagle Ford well, how is that holding up relative to -- I believe you put a 500,000 EUR bogey out there. Is that holding that type curve?

It's dropped off somewhat, Welles. At this time, it looks like it's probably a 350,000 ultimate kind of well. That's BOE equivalent. I think what we need to do is 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 test it that way. But at end of the day, that type well in the Fojtik is still economical, number one. Number two, I think we can do better than that. And number three, we have got this interval, this upper Eagle Ford [mapped] across our acreage, and there are many areas on our acreage that we can continue to exploit this upper Eagle Ford. So I think the jury's still out at this time, but the Fojtik well, the first well, is an okay well.

And what's the additional mapping? Any update to the kind of one-third of your acreage being prospective number?

I think that number still holds true. To be honest with you, I've never [prelimiterred] how much of the acreage is prospective versus how much we have, but I think that one-third is probably still fairly accurate.

Okay, great, that's all I have. Congratulations on the quarter. Thanks.

Thanks.

(Operator Instructions)

Biju Perincheril, Jefferies.

Good morning. Couple of questions. On your well count in the Eagle Ford, can you talk about what is some of the tightest spacing assumed in there -- the distance between laterals?

John, I'll let you answer that question, please.

Sure. We've successfully tested on, I think, at least three different pads downspacing down to 400 foot between laterals. That seems to be working very well.

As far as the well count throughout the entire leasehold, it will vary between 400 feet where it -- where we can fit it in. Some of it is going to be 500 foot because the initial wells were drilled on a 1,200-foot spacing, or 1,000-foot spacing. So when we downspace that, the most logical sense is to test the 500 first. We have some upside in some of the areas where we've got the 500 foot, but we'll drill the 400 foot wherever we can. In some of our less proven acreage where we have fewer penetrations, I think we've got it down to 700 foot. So we've still got some room to run in the southwest part of our acreage.

Okay. And in that southwest part, you haven't actually drilled wells on the tighter spacing; is that right?

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

Okay. Thanks. And then also, are you including any upper Eagle Ford locations?

No.

Okay. And then a question on guidance. It's clear what the oil numbers you tweaked down the lower end, but what's driving the uptick in NGL and gas guidance? Is that some East Texas or Granite Wash holding up better or --?

Biju, this is Baird. The reason being is you go to the east in Lavaca County, you've noticed on some of the gas rates alone, the GOR is increasing as we go to the east on that farm-out acreage. I think the highest we have seen is maybe 2,500 to 3,000 standard cubic foot per barrel. So we've had to adjust the type curve for some of those eastern Lavaca County wells, and because they are still very good wells, but the gas -- the proportionate amount of gas has increased on those wells.

Okay, so it's all driven by Eagle Ford mix?

It is. It is all Eagle Ford. Yes.

Okay. Got it, thank you.

Adam Leight, RBC Capital Markets.

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

It's more of a function of geology. As you go to the east, you go deeper -- it gets deeper. So because of these shale resource plays, the gas component tends to get higher, but it's strictly geology.

With the acreage you're adding, is that going to continue to move towards the higher gas proportion?

There is some acres we are -- because of our success on the eastern part of our Lavaca County acres, some of the acres we are adding is adjacent to that. So you would expect GORs to be higher. We have adjusted our type curves in this most recent forecast, which has caused the adjustments in our guidance because of that. We're also acquiring acreage up, whereas the GOR would be more so in the 500 to 1,000 standing cubic foot per barrel, which is pretty typical on some of the higher volatile oil stuff. So it's a mixed bag as far as where our acreage is being acquired.

Okay. That's great, thanks. On the completion contract, did you change contractors, or did you just get a better deal with your existing provider?

We changed.

Okay.

We have two service providers right now.

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?

John, why don't you try to answer that question, please.

I would say probably 75% of the cost savings is going to be to more favorable pricing. The rest of the cost savings is coming from the design side where we've discontinued the use of ceramic, and gone to a resin coat tail-in with white sand and 100-mesh mix in the actual design. So 75% of it probably due to more favorable contracts, and 25% of that due to completion design.

Great. And just, on the assumptions, you have LOE bumping up compared to what you recorded in the second quarter. Is there a reason for that?

On a barrel basis, it's about the same, so it's just higher volumes.

You're going from $4.94 to $6.

Second quarter -- sorry, I thought you were talking about from first-quarter guidance to second-quarter guidance. I apologize. It would just be 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 is generally the cost.

We have had to increase our H2S scavenger chemicals and some paraffin 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 on even some of the new wells because we own them. So as we pull them out, and put rock pumps on, in some cases we will take those, have them refurbished and run them back in. There are advantages to using ESP, so we'll continue with that effort because we own some of these. But in general, it's primarily chemical and ESP costs.

You're not sand bagging [us that's all]. On the asset sales, I get it on the gas assets. If I missed it, I apologize -- did you mention anything on the midstream side?

Yes, we have an effort in place right now. We have an outside firm who we have engaged to attempt to sell our gas gathering and the rights to lay an oil gathering system. The oil gathering is a very valuable component to the overall gathering value in the 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, late fourth quarter, we'll proceed. If not, we won't proceed. We aren't going to give it away.

Can you give me a sense of how much value is in the borrowing base for that? Or the anticipated borrowing base --?

There's no value in the borrowing base for midstream. We would expect to take no borrowing base adjustment for that.

Okay. How about the gas assets?

Same -- nothing in the borrowing base for the assets per se.

I think he was saying the gas -- if we sold some gassy asset reserve -- there would be a borrowing base.

There, there would be. There would probably be about a $40-million adjustment for either the Granite Wash or the Selma Chalk, roughly.

Okay. That's great for me. Thanks.

Okay. Thank you.

Hoshang Daroga, MLV Company.

I want to know, as you downspace, are you seeing any frac interference, or do you plan to run any micro seismic, or is micro seismic run already?

John, why don't you answer that question, please.

On the micro seismic, there's some additional things we would like to do on the technical side, but we need to do them all together, instead of piecemeal. We want to look at the micro seismic along with some additional radioactive tracing, and production logging in conjunction with a pad, so we can get the most benefit from that. That will probably be a 2014 effort. I think our drilling schedule for 2013 is fairly firmed up for 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.

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

Thank you.

David Snow, Energy Equities Incorporated.

Hi. Just as a ballpark, what do you think the comps would suggest you might be able to get for the gas gathering?

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

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

It helps. It's something we don't get any value for, so it wouldn't help it appreciably, you're right, but it does help.

And at this point, do you see the need to bolster your balance sheet with more equity as you look at opportunities for picking up more acreage out here in the Eagle Ford?

No, no. No. We feel, with the CapEx program we have over the next couple of years, the six-rig program, a fairly aggressive leasing effort in the Eagle Ford, and the growth of our production in 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 built on organic growth and organic improvement of the balance sheet. And again, I'll say it for the 10th time, and will continue to say it, we are committed to get this done here by the end of '15 and '16.

Okay, and then last, after allowing for some interference on downspacing, have you factored that into your type curve, your EURs now?

Yes. It will be -- there are continual adjustments. As John said, interference is not necessarily bad. In fact, we think it's a positive. And as we drill these longer laterals, and get this shattering effect because of the zipper fracs and the closer spacing, we think over time we should be able to adjust those type curves up. But we're going to take a wait-and-see attitude in order to do that, of course, before we make those kinds of rushed adjustments to type curves.

What's your current EUR?

We use around 400,000 barrels equivalent for Gonzales, and 500,000 for Lavaca County.

Great. Thank you very much.

Thanks, David.

[Derek Wornderlick], Southwest Securities.

I appreciate it. Good quarter. My question involves when tighter laterals are closer in, if there are compromises to existing wells nearby, the closer fracking or clogging up existing, is it economically feasible to go and rework existing or reclean out to make sure the [compromise] didn't effect too much?

I think maybe a better way to ask that question -- when we see interference, if we have an existing well, and we come back in and downspace, and we -- they see interference with the existing well, that well typically we will shut it in beforehand, number one. We'll shut that well in some period of time before we start fracking any offset wells. What you see is an increased 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 cases, because of the communication, you 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.

As far as maybe what your question was -- if we thought about going back in and refracking some of these existing wells? At this time, no. It gets somewhat mechanically, operationally complicated in order to do that. You'd have to do it through coil tubing or through tubing, and try to isolate the existing perfs and clusters, which gets dicey. You'd probably have to isolate segmented parts of the lateral itself, and try to do it overall, and try to refrack. Something we'd like to try to do at some point in time. We just don't think we need to do it right now, but it is something we will probably try to do over time.

Thank you.

Thank you.

David Snow, Energy Equities Incorporated.

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

If 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 it will -- may be a little bit less in the NGLs, maybe a little bit less, and the residue gas is a little bit higher. But it's not materially different.

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

Lavaca County is typically about $1 million higher because of the intermediate string of pipe.

It's about $7.5 million and $8.5 million, or what was the --?

I think John said earlier it was $8 million to $9 million for Lavaca County, and $7 million to $8 million for Gonzales County, depending on lateral length.

Okay. And then what's the royalty there?

Usually 25%.

Great. Terrific. Thank you very much.

Thank you.

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

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're up and running, and have things integrated. So from that standpoint, our employees have done a fantastic job.

We have a good position in Eagle Ford right now. To 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 bullseye right now. We have 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'll say it I guess for the 11th time now, our plan is to be self funding that CapEx program into late '15, early '16. Again, I can tell you we are committed to this goal over the next couple of years. With that, thank you very much.

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.