Ranger Oil Corp (ROCC) 2011 Q2 法說會逐字稿

Good day, everyone, and welcome to the Penn Virginia Corporation's second quarter 2011 earnings conference call. Today's program is being recorded. At this time for opening remarks, I'd like to turn things over to Mr. Baird Whitehead, Chief Executive Officer. Please go ahead, sir.

Thanks, Kelly. Good morning and welcome to Penn Virginia's second quarter 2011 conference call. I'm joined today by various members of our team, including Nancy Snyder, our Chief Administrative Officer; Steve Hartman, our CFO; Jim Dean, our Vice President of Corporate Development. And also joining us today is John Brooks, our Vice President and Regional Manager of our Houston office. Prior to getting started, we'd like to remind you the language in our Forward-looking Statement section of the Press Release was issued last night, and the Form 10-Q that has been filed, will apply to our comments today. We'd like to begin our discussion this morning by expanding on the earnings and operational update press releases that were issued last night. As stated in our Press Release, our second-quarter results demonstrate we have made significant progress, we think, in transforming Penn Virginia from a focus which had been predominantly natural gas to a new focus on oil and natural gas liquids, which has resulted in higher revenues and cash flows.

We had a solid quarter, we think, with improvements quarter-over-quarter in revenue, EBITDAX and adjusted earnings per share, not withstanding a decline in natural gas production. Product revenues of $73 million were up 39% over the second quarter of 2010, and up 8% sequentially from the first quarter of 2011. Oil and liquids revenues of almost $35 million were up 156% over the second quarter of 2010, and 31% from the first quarter of 2011. Similarly, adjusted EBITDAX of $47.5 million was up 44% over the second quarter of 2010, and 8% sequentially from the first quarter of 2011. This improvement in EBITDAX was attributable to the increase in oil and liquids production and associated revenues, as well as the improvement in direct operating expenses which decreased $2.47 per Mcfe from $2.84 per Mcfe in the second quarter of 2010. This does continue to be a priority of ours, and was one of our decision points in the divesting of our Arkoma assets which had a higher operating expense.

We had an adjusted net loss of $11.9 million and an earnings per share of a negative $0.26, which excludes charges from impairments, the loss on the extinguishment of debt and other non-recurring items, and was $0.05 less than the second quarter of 2010 due to lower hedge settlements, but $0.24 better than the first quarter of 2011 primarily due to the lower exploration expense. Second quarter production of 11.7 Bcfe equivalent was 12% above the second quarter of 2010, but approximately 4% less than the first quarter of 2011, due to the 9% decline in our natural gas production associated collectively and primarily, with our Selma Chalk, Mississippi assets, East Texas and Granite Wash natural gas production, and the result of a significant reduction in overall drilling activity in those plays during this year. On the other hand, our oil and natural gas liquid production has increased significantly representing approximately 24% of the quarter's production, as compared to 13% in the second quarter of 2010, and 20% in the first quarter of this year.

Oil and liquids production has increased to 472,000 barrels, or over 5,100 barrels a day, in this quarter versus 223,000 barrels in the second quarter of 2010, or 2.400 barrels a day. So we have more than doubled our liquid production year-over-year. In the first quarter of this year, our total liquid production was 408,000 barrels, or 4,500 barrels a day. So therefore, our second quarter total liquid production has increased about 13% from the first quarter to the second quarter. And really, this is before we have kicked into high gear our Eagle Ford program, and the recent completion of some very good wells. Both the overall decline in natural gas production with the lack of any drilling and further adjustments, to the expected Granite Wash production due to the communication issue that we had previously discussed, along with the sale of our Arkoma assets, we've had to reduce our production guidance for the year, even though our oil and natural gas liquid guidance is increasing. And Steve will get into more detail of this, in a little bit later.

Now let me talk about the Eagle Ford Shale. We released some very detailed information about our program to date, in that play. We have drilled some truly outstanding wells, and the result of those wells with initial potentials averaging approximately 1,100 barrels a day equivalent for the first 12 wells, and about 700 barrels a day equivalent on a 30 day basis for the seven wells for which we have that data. The well that has been on production the longest period of time is the Gardner well, which has produced about 96,000 barrels of oil equivalent after six months, and is still producing about 350 barrels a day equivalent. At this time, we think this could be up to a 600,000 barrel equivalent type of well.

If you use the production data from the Gardner well, as the basis of the type curve, and using the shape of that curve and applying it to all the wells we have turned and aligned, one can make a strong case, the average reserves of the wells drilled to date can be up to 500,000 barrels equivalent, taking into account the natural gas liquids and shrink. If you take that type curve, that 500,000 barrels, that generates a 90% after tax rate of return, with an after tax PV-10 of $6.6 million. And that's using a $7 million drilling and completion cost, and a $90 per barrel flat oil price. So this truly is, we feel, a very, very good area. At the same time, I just want to remind everybody, we don't have a lot of data, and we cannot project the 500,000 barrel number across our entire acreage position, but geologically, we think we're in an excellent area. We believe our wells, which have averaged about 4,100 feet in lateral length with 16 frac stages to date, which we think we can drill going forward for about $7 million, is in a very favorable geological area, with natural fracturing probably playing some material role in the results of the better wells.

The Eagle Ford is not significantly thick in our area, it averages about 100 feet, but it does have decent porosity, and we have seen indicators while drilling that would indicate some natural fractures. In fact, in a few cases, with only about 1% of the flat frac fluids returned, some of these wells are already producing over 1,000 barrels a day. And really, in my experience, I have not seen something like this. It probably does tell you the natural fractures are playing some role. Our wells have had an average of approximately 90% well head oil and that natural gas liquids, with about 10% being residue gas associated with the processing.

We have three operator rigs. We drilled 14 wells, completed 12 of those 14. We expect to get another two to three wells completed during the month of August. For the total this year, we now will drill 34 gross, almost 28 net wells. This is up from 29 gross and 24.4 net wells that we had previously utilized in our forecast, and we expect to drill approximately 37 net wells in 2012. So we plan to keep this program growing. I want to remind everybody we do have the rigs in hand, we have two of the three rigs under long-term project. We have a long-term frac contract in place, and we have a processing arrangement that is up and running. So we don't have to sit around and wait. We drill these wells, we complete them, we have them in line, anywhere from 30 to 45 days after spud.

Based on the initial well results, with the expectation we can replicate those results going forward, we expect volumes from the Eagle Ford, which is about 8,000 barrels a day gross and 5,000 barrels a day net a day, to increase between 11,000 and 13,000 barrels equivalent per day gross, or about 7,000 to 8,000 barrels per day equivalent by the end of this year. And that assumes a three rig program. And in keeping this going into 2012, we'll probably spend up to 75% to 80% of our program drilling Eagle Ford wells in next year. I know there's been a lot of comments, about whether we can get you the size large enough in the Eagle Ford to make it more material. And I had previously said, I admit to it, we wanted to get the 25,000 acres by the end of the year. I didn't want to pay anymore than $6,000 an acre. But with some of these recently announced transactions in the Eagle Ford approaching $20,000 an acre, I do realize now that, that goal was going to be very difficult to achieve. But based on our results to date, based on that 500,000 barrel type curve, we can justify paying more than $6,000 an acre today. I'm not going to say exactly what we would pay, but there's clearly good reason to pay more than $6,000 an acre, based on how far we've come up on the learning curve, and the experience of the wells we have drilled to date.

So to remind everybody, we have about 17,000 gross and 14,000 net acres in this play, almost all of which is in Gonzales County. If you look at it on a map, it's very blocky, with the ability to in general drill some fairly long lateral's on those blocks. But due to the compelling economics of this play, we are going to attempt and keep selectively trying to attempt to add acreage either through grass roots leasing or through acquisitions. We have 140 locations, well locations on the acreage we have. That gives us up to about a three year drilling inventory. So there's not a gun to our head, like we're going to run out of things to do in six months. We have more than enough period of time, to keep plugging along and keep adding to what we have.

I'm not going to say a lot about the Marcellus at this time. We did announce our completion results of our first three wells, three or four weeks ago. It did miss our expectations, but again, it's way too premature for us to walk away from this play. Can we improve upon the results of these first three wells? I don't know for sure. But we need to keep in perspective, these first three wells, really only tested about 1,000 acres of a 35,000 acre net position up in Potter and Tioga County. So there's a lot of room left to test. But we do think we can improve upon the results. We plan on testing our acreage in the eastern part of Potter, western part of Tioga County. There's a good reason to be made, and we need to be tweaking the direction of our lateral's to more of a north 20 to 30 degree west up north. And there's also good reason to be made, that we ought to be making some tweaks in the completion procedures themselves. So we're taking all of these into account right now, and we plan on testing the remaining part of our acreage as the year goes on, and into 2012.

Just to remind everybody, we should have these first three wells we did drill, probably in line by the first of September. And I want to briefly touch on the Granite Wash. As reported, a major part of our reduction in the production guidance was due to the communication issue, that we continue to see as additional down-spaced wells are drilled in our east section, in our south Clinton field. Right now, the longer term plan is to drill these wells on 160 acres spacing, but between ourself and our-- and the other operator. And after taking into account those communication issues, which we have spent a lot of technical time on here over the last two or three months, we have reduced the IP rate of the type curve going forward. The early time decline rates are actually less than what the original type curve used. But at the end of the day, our new type curve, that we think we can replicate going forward is about a 4 Bcfe equivalent. That generates about a 20% to 25% after tax rate of return at a flat $5.00 gas price, NYMEX gas price, and $90 per barrel oil.

We have taken some positive steps over the last few weeks to shore up our liquidity, and Steve will discuss this in detail. We closed on a new credit facility with more accommodating leverage covenants. In addition, we have signed a P&S agreeing to sell our Arkoma assets for about $30 million. The increase in these leverage ratio covenants, together with the expected increases in our oil-driven cash flows in the second half of this year and into 2012 more aggressively, to hopefully put to rest any anxiety about our liquidity, not only today but into next year.

The outlook for the balance of 2011 into 2012, it really is straight forward. It's drilling and completing Eagle Ford Shale wells. The expected impact of this program on our production and cash flows is expected to be significant towards the second half of this year, into next year. Despite lowering production guidance for the second half of 2011, due primarily to the performance issues of the Granite Wash as I had discussed, and the pending sale of the Arkoma assets, we expect to more than make up for that production revenue growth over time from the Eagle Ford, and other potentially oil or clay types that we continue to review and consider entrance into. But based on what we know about the potential of our Eagle Ford Shale acreage, we could do nothing but Eagle Ford Shale for the remainder of this year in 2012, and we think we could grow our production and cash flow at very attractive rates. Yes, we're essentially a one trick pony at this moment, but we think it's a pretty good looking pony.

We continue to review opportunities to expand our inventory of oil drilling locations, focusing on the increasingly competitive Eagle Ford Shale, but also acquiring positions in other established or newer oily plays that may not be near as pricey. With our current Eagle Ford Shale position, very acceptable results in the Granite Wash since it has a liquid component, and still you got (inaudible) over Cotton Valley horizontal program, and we think continue -- can continue to throw off very acceptable returns, since again, it has a material liquid component, we believe we have more than adequate inventory of drilling opportunities that can provide near term growth.

But having said that, we also understand the sense of urgency in increasing that inventory of oil weighted investment opportunities, and are working diligently to increase that inventory without taking on undue risk, sacrificing quality or overpaying. We expect these efforts to bear fruit at some point in time in the near term. And I feel that we have the team and the financial flexibility to execute on those opportunities. So with that, I'd like to turn it over to Steve Hartman, and have him give you an update on our financial progress for the quarter. Thank you, Steve.

Thanks, Baird, and good morning, everyone. I'll start with our second quarter financial results summarized on page two of the release. This review will generally be comparing our second quarter 2011 results with our prior-year quarter results, with some extra color added where warranted. On with the financial performance, as Baird mentioned, our product revenue was strong this quarter, coming in at $73 million. This is up from $52 million in the second quarter of 2010, a 39% increase year-over-year. This increase was primarily driven by volume increases, especially oil and NGL volumes, and also price increases with increases in both realized oil and NGL prices. Our oil and NGL revenue was notably up this quarter, at $35 million for the quarter or close to a 50% increase in total -- 50% of total revenue. This is up dramatically from $14 million, or 26% of revenue in the prior-year quarter, and up from $27 million or 39% of revenue last quarter.

Realized prices were $98.45 per barrel of oil, and $52.04 per barrel for NGLs this quarter. This is up 34% and 49%, respectively, over the prior-year quarter. Our realized price for natural gas was $4.32 per Mcf this quarter, which is relatively flat compared to the prior-year quarter. Including cash settlements from our hedges, our realized price for the quarter for natural gas was $4.80 per Mcf, and we did not have meaningful hedges in place for oil NGL to affect the realized price there. As Baird mentioned, our direct operating expenses improved this quarter, coming in at $2.47 per Mcfe, that compared to $2.84 for the prior-year quarter. This quarter included some unexpected one-time R&M costs in Mississippi, adding about $0.005 to our LOE cost, and an accrual for out of period cost of approximately $600,000, adding another $0.05 to LOE this quarter. The prior-year quarter included restructuring costs and G&A of $4 million, or about $0.40 per Mcfe.

Now this is a good point to pause and comment on our cash margins. Our margin, which I'm using adjusted EBITDAX as reconciled on page eight of the release of the proxy, was $48 million this quarter, up 44% from the previous year quarter. Adjusted EBITDAX, of course, is a direct determinate of our liquidity, so we're pleased to see such a strong increase in this measure. More on liquidity in a minute.

And back to the income statement for some non-EBITDAX items. We reported exploration expense of $19.4 million for the quarter, $2.1 million of this expense was disclosed on last quarter's call, as a dry hole expense in the Mid-Continent. And the remaining difference is primarily an increase to unproved leasehold amortization, which we previously disclosed would be higher than in previous years, due to the land acquisitions in the Eagle Ford/Marcellus Shales. We are reporting an operating loss from continuing operations this quarter of $71.9 million, or $1.57 per share. The loss is primarily due to the impairment we took related to the non core Arkoma asset sale, a loss on extinguishment of debt related to refinancing our convertible notes which were due in 2012, and the increase in exploration expense, which I touched on.

Our adjusted net loss attributable to PVA, a non-GAAP number that is reconciled on page eight of the release, was $12 million, or $0.26 per share this quarter. We adjust the GAAP determine net loss for non-cash impacts from hedging, restructuring cost we incurred primarily in 2010, impairments, the loss on refinancing debt and as well as gains and losses on asset sales. This result was lower than the second quarter of 2010, but is a $0.24 per share improvement over last quarter. The adjusted loss can be mostly explained by the higher exploration expense related to higher land amortization cost. We expect improvement in the future, the sale of the Arkoma assets, which we carried on our books at an operating loss to current natural gas prices, would help us toward achieving profitability toward a -- below the line going forward, plus by monetizing a relatively low return asset, it allows us to reinvest the money in higher return core projects.

Onto capital resources and liquidity on page four of the release. The big news for our capital resources and liquidity this quarter, is that we closed on our newly refinancing credit facility on Tuesday, which Baird touched on. This was announced on a separate press release yesterday, but essentially we refinance our existing $300 million commitment and $380 million borrowing base to a -- deal to a 5-year deal. It improves our leverage covenant to 4.5 times debt to adjusted EBITDAX through June 2013, from it's previous and current level of 4 times. And it lowers our cash interest expense, with lower unused commitment fees and lower spreads over LABOR, it will save us about 50 basis points over our current interest rate. Under this new deal, we will have approximately $260 million of liquidity pro forma as of this quarter-end. And this availability will expand over time, as we increase our cash flows related to the Eagle Ford development. We have an accordion feature to allow us to increase our commitment up to the borrowing base levels with additional commitments from one or more lenders, which in today's very strong bank market, I have confidence we would be able to at our option.

And one more thing to consider on our borrowing basis, we do not currently have any value on our borrowing base for any Eagle Ford development. The borrowing base was calculated using year-end 2010 values, when we did not have any proved reserves in the Eagle Ford yet. I expect to receive value for the Eagle Ford in our mid-year re-determination this fall. And with all that said, our liquidity now and with the expanding cash flow in the next year, is more than sufficient to fund the 2011 and 2012 capital programs. Our cash and cash equivalents on hand at quarter-end were $31 million. Our debt consisted of $300 million Senior notes we issued in April this year at 7.25% that are due in 2019, $300 million of 10.375% Senior notes due in 2016, and $5 million and 4.5% convertible subordinated notes due in 2012, that's what's left over from our tender offer process that weren't tendered, and nothing outstanding under the credit facility.

We mentioned in the release that we completed the refinancing of the convertible notes due in 2012 during the quarter, and we discussed this transaction at last year's quarter call. And essentially, we reviewed this as an opportunity to refinance some debt that was going to go current on the balance sheet this year, with long-term fixed rate notes at a very favorable rate. We termed out the debt for eight years at 7.25%, which is at or very close to historical lows for our credit quality. And at the same time, we raised money for the 2011 capital programs, and lowered our effective interest rate. So overall, we're very pleased with this deal, even though we had to recognize a mostly non-cash loss and extinguishment of debt this quarter, representing unamortized origination discounts from issuance and fees and some tender premiums.

Moving on to hedging, just a quick comment on hedging. Our cash settlements from hedging in the second quarter were $5 million, $4.1 million of which were due to commodity hedges. And this provided a $0.48 per Mcf uplift in our natural gas realized price, and just a very slight decrease in our realized oil price. The table on page ten of the release summarizes our hedge position as of today. As the percentage of the mid point of 2011 guidance, we have 60% of our remaining natural gas production hedged for the remainder of the year, and 41% of the remaining total commodity price exposure, which includes oil for 2011. We expect to add oil hedges, as we bring on more volumes in the second half of the year.

Finally, moving on to guidance on page nine of the release, and starting with production, we are tightening our guidance towards the lower end of previous range, at 48.5 to 50.5 Bcfe. The primary reason for this change, as Baird explained is natural gas, and specifically related to the sale of our Arkoma assets, which was about a B of loss of production and well communication issues in the Granite Wash. We're raising our oil guidance to 1,450,000 to 1,600,000 barrels which is a 9% increase on the mid point. This is obviously due to the success of the Eagle Ford program, as we continue to drill with three rigs, and improve our spud to sale time. We now expect approximately 30% of our 2011 production will be from the higher margin oil and NGL production, and at least 40% in the fourth quarter of 2011. We expect to see the majority of the ramp up to be in the second half of the year, as we see the benefit of the three-year program kick in, and the full benefit of NGL processing which started in June. We expect an exit rate of approximately 10,000 barrels per day net oil and NGLs going into 2012, about 70% of which is produced from the Eagle Ford.

We are not materially changing our operating expense guidance numbers, except for a slight increase to the gathering and processing expense related to a new NGL processing agreement, which will ultimately increase revenue and improve our margin, lower production and ad valorum taxes, and slightly higher non-cash share-based compensation expense. The guidance implies a drop in LOE in the second half of the year. We expect it, because we sold our relatively higher costs Arkoma asset, and because the Eagle Ford wells have a low cost LOE, relative to our overall cost structure. So overall, we do expect a drop in LOE in the second half of the year. Our exploration expense is higher, primarily due to unproved property amortization, as we continue to add land in our key plays and higher seismic costs. We expect this will come down over time as we move proved Eagle Ford reserves in the DD&A, offset by any new land acquisitions we may take on.

For CapEx, we're raising the top end of our guidance by $10.00 to $380 million, and tightening the lower end of the range to $360 million. This increase is primarily due to increased development well expenditures in the Eagle Ford, as we've improved the spud to sale time, and therefore need more money keep all three rigs active through the end of the year. There is also some money added for the pipeline construction in the Marcellus, which we had previously assumed would be contracted out to a third party. It's worth noting, that for the second half of the year, we're actually looking for a lower per quarter capital spending rate, as we focus in on the Eagle Ford Shale development, and spend less money in the Mid-Continent Appalachia. And that is all I have, Baird.

Thank you very much, Steve. Just comparing to where we were three months ago, even though it's a work in progress, we think we have made a lot of progress in transforming this Company from predominantly a gas producer, to a Company that is much -- that tends to become much more balanced between oil and gas. We also have a financial position which will enable us to handle the changing market conditions. And to also capitalize, what we think might be attractive expansion opportunities down the road With that, Kelly, we're ready to go ahead and take some questions.

Thank you.

(Operator Instructions).

We'll go first to Neal Dingmann with SunTrust.

Good morning, guys. I had 2 quick questions. First, great detail on your Eagle Ford wells. Was wondering -- obviously, the success that you had on that #9-H, and the amount of frac stages there. Just your thoughts, kind of going forward, I guess, with costs around that, as far as lateral lengths and frac stages. I guess I am asking, will it be more on the lines of that 18th stage, or even above that going forward?

John Brooks, our regional manager is on the call, and he oversees our Eagle Ford program. So I'll go ahead and let him handle that question.

Well, the #9 was an outstanding well. We had 18 stages on that 1, we had them spaced probably around 250 foot. So I think that well -- it was a combination of more stages, and some natural fracturing that we probably entered into. I think there is a good chance also, that we're getting contribution from the overlying Austin Chalk.

Okay, good answer. Then just a second question, if I could follow up. Over in the Colony Wash, just your question, your comments on the press release just about the type curve and the forecast that price may be coming down a bit. Just wondering now on this post processing basis, what you're estimating for EURs, or maybe how you see the AFEs as stacking up?

We think that going forward, taking into consideration geological situations and the communication issue, our future type curve is about 4 Bcf equivalent, including NGLs. Thank you.

Stephen Berman, Pritchard Capital Partners.

Good morning, gentlemen. Baird, can you just talk about -- maybe looking out over the next year or 2, your thoughts on the Haynesville. I know you're not drilling there now. GMX just suspended their Haynesville drilling. Thoughts on horizontal Cotton Valley, any exploratory drilling in the Mid-Continent? Just other things outside of the Eagle Ford.

Good morning, Steve. In east Texas, the only thing we have planned on the horizon, that being next year, would be maybe drilling a handful of horizontal Cotton Valley wells. We have been really very pleased with the Cotton Valley program we drilled in 2010, and we think we have learned a lot. We think we know where we need to have a lateral within the overall Cotton Valley section. The upper part of the Cotton Valley is oilier than the lower part of the Cotton Valley, and we feel that we've got probably 15 to 20 good, excellent locations that we could jump on if we wanted to in the Cotton Valley. The Haynesville, you can make a case that -- because, again, the 2010 [program], we still think that the average reserves of those last 5 or 6 wells that we drilled is about is 7 Bcf and we have got some wells now that have made, approaching, 1.5 to 2 Bcf has been online now for a year or a little over a year. Some there's some very good wells we drilled last year.

We directionally, again, we got the lateral we think nailed down to where it needs to be, we got the locations within our overall acreage positions that are high-graded, the frac stages have to be higher than lower as far as number of stages, but again, they're pretty expensive wells. If we could drill a 7 or 8 Bcfe well at $10 million, it does make some sense. We have no plans of resurrecting that program, of course, because of what it is. In the Mid-Con, in a short term, we're going to stick with the Granite Wash primarily outside operated by Chesapeake, even though we have some disappointments, admittedly, on our exploratory program, we still have some things teed up. We have a viable prospect that we either are or just recently finished shooting a 3-D on that will help us pinpoint where the locations need to be, it's a horizontal plate, it's a fractured, carbonate plate. We've got some other Cleveland top-wash sand plays that we need to test.

This last dry hole we drilled in the first quarter, this [Lockridge] well that we previously reported on that we expensed the second quarter, is not very far away from what Range is doing in the St. Louis. And we feel we have those opportunities on a part of the acreage and along with some [morrow] opportunities, but we need to shoot some 2-D and 3-D on that. We will probably get kicked off on that at the first of next year, with a 10,000 to 12,000 acre very blocky position there, we think it's something we need to continue to explore on. I think I answered your question.

You did. Thank you. And 1 more, just over and above the Arkoma Basin non-core asset sale, any thoughts on other liquidity type events such as that, or JVs or anything along those lines going forward here?

Well, we have said publicly that our horizontal CBM back east may be an asset that we may decide to sell at some point in time, so, that is something that we could sell if we wanted to. It's probably -- it's not a big ticket item, it's probably sort of the same size at the Arkoma. That is 1 way. JVs -- we will continue to entertain any decent offers on our Marcellus, or there is still is some interest out there on our position, even with the [amassed] results we had, so we will continue to try to explore finding a partner for that play also.

Okay. And that is it for me. Thanks, Baird.

Thank you, Steve.

Welles Fitzpatrick, Johnson Rice.

Good morning. On the -- how are those 88-acre spacing tests in the Eagle Ford holding up and do you plan for anything, any tighter tests this year?

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

Currently, we're drilling on 1,200 foot spacing on the wells, so depending on the actual length of the lateral, I think the acreage spacing is somewhere north of 80, but we do have some plans to test a tighter spacing down to the south of our acreage later this year.

Okay. And with the Eagle Ford leasing kind of tightening up a little bit, would you guys consider broadening the previously talked about target area, maybe including some wet gas areas of the play?

Yes. Certainly, Welles, and we realize, considering what the current deal flow is out there is that there some other areas that we look very favorable on. We have spent a lot of money and a lot of time on researching this, and we know exactly where want to be in this play and if we know exactly where we want to be in this play because of results and economics, you can afford to spend higher bucks per acre, of course. If the right opportunity comes down the road, we would pull the trigger that made a lot of sense to us. Having said that, there may be some reason for us to expand the Eagle Ford out of the conventional area from an exploratory standpoint. We're not to that point yet, but there are some exploratory ideas in the Eagle Ford that probably will get our attention in the near-term also.

Okay. And a clarification, the 15 to 20 locations in the Cotton Valley, was that referring just to the Davis?

Yes.

Okay, and 1 last 1, any new updates on the deep rights on the Selma Chalk acreage?

At the end of the day we don't have a lot of deep rights. Most of the rights we have, within in the general Selma Chalk is Selma Chalk alone. We do have some but it's fairly immaterial.

All right. Perfect. That is all I have. Thanks, guys.

Okay.

Eliot Javanmardi, Capital One Southcoast.

Good morning guys, I just had 2 quick questions in regards to the Granite Wash situation that you have going on. 1, how does this affect your field development plans going forward in that area? What do you see potentially happening there? And also, do you foresee an increase in costs in order to produce there, particularly related to acidizing stimulation or any other efforts to boost those type curves or try and achieve a little bit more production?

Well, the plan is to continue to drill on 160 acre spacing, i.e. 4 wells per section, that is Chesapeake's plan, and we will stick with that plan even though selectively there may be a few wells we decide to go [90%] on because of the communication issue. But they will probably be a few. We have no reason to expect anything is going to change on the spacing. In fact, there has been some discussion that they may want to drill a fifth well, but in any case. As far as cost, the costs have gone up in this play. The drilling has gotten a little bit tougher in certain parts of where Chesapeake is drilling right now. The costs have gone up to a $7.5 million to $8 million per well. The 20% to 25% after tax rate of return I mentioned earlier was based on those higher costs, and it's primarily on the drilling side. The rotating days have increased on these wells. It's just hard stuff, the Granite Wash can be tough stuff and it can eat some bits up, even PVC bits, and the rotating days have increased here over the last 3 to 4 months or so.

I appreciate that. Thanks.

You're welcome.

John White, Triple Double Advisors.

Good morning, thank you for taking my call. You mentioned liquidity and cash, was it liquidity or cash flow that is sufficient to fund your needs through 2013. I'm sorry, I missed that.

It's both. Our liquidity which is supported by our cash flow is sufficient to fund the program for 2011 and into 2012, and keeping our leverage statistics and all of our credit stats very much in line with our peers.

Okay, so it's a combination.

Yes.

And the borrowing base, I noticed was higher than the face amount on the credit facility. Can you talk about that?

That is a decision that we made just basically to save costs. It costs us money to have that commitment in place and since we had cash on the balance sheet and no real need to access the full then $400 million, $380 million now, we didn't see a reason to take down that commitment from the banks, and that saved us about $375,000 per year. So that's material money. So we keep $300 million there as the commitment and we have a very strong bank group, it's led by JPMorgan. We have some of the top banks in the energy space in our bank group, and I have absolutely no worries that if we needed or wanted to access that last $80 million, we would be able to do so very quickly. It's just a cost saving measure.

Okay, very good. Final question on the Gonzales County activity. In general, what are the well depths and completed well costs?

John, why don't you go ahead and take that 1 please.

The TVD of the wells is roughly about 10,500 foot, and with the lateral and the vertical section, we're TD in between 15,000 and 16,000 feet. The completed well costs are running around $7 million.

Thanks very much.

David Snell, Energy Equity Incorporated.

Hi, was trying to get -- what was the number of acres that you have looked at with the Marcellus wells that were not as good as you thought?

3 wells were -- 2 wells were good from the pad, the third well was drilled from its own pad, but in general, those 3 wells were pretty close to one another so we feel like we've only really tested about 1,000 acres. A small part of what we have in total.

Does that tell you anything about the surrounding acres?

No, not really, I mean it sort of puts you in the fairway. Yes, I wish they would have all been 10 million-a-day wells but they weren't. Even though you're testing 1,000, you would be more concerned about the acreage fairly close to that. There are some reasons that the we could make, consulting with a structural geologist type who has a lot of history and directionally, we should be putting a lateral in a different direction, which improves the chances of contacting the natural fracture system that exists, so we will look at changing the direction. We also will look at altering the frac job itself. Primarily trying to put probably some higher concentrations away.

The Marcellus in general can't have a higher clay content. It's not real high where we are, but we probably suggest that we should have run some higher concentrations which gives you a wider propped width and tends to offset some embedment issues that you may run into with the softer formation. I probably told you more than what you wanted, but we show that there's a case to be made that we can -- this is theoretical, of course, but you could have taken the results we announced and you could have doubled them based on the lateral distance being in the right direction at a minimum and maybe some additional improvement on top of that because of a better frac job.

Is there any surrounding operators that gave you any additional color?

Yes, Alterra is fairly close by to our eastern acreage, they have drilled some good wells, Shell Eastern or East Resources, they, that's in their backyard, so we have every reason to expect as we go to the east. That's the other advantage of getting closer to already known success, industry success. So, yes.

How far are the existing wells from that eastern area?

David, I don't know exactly but it's probably a good 30 miles away or so.

Okay. All right. Thank you very much.

[Bob Zahani], RBC.

Give us a little color around the decrease in production taxes sequentially and if that is sustainable going forward?

We think that that is sustainable going forward. We were fairly conservative when we did our initial budget at the beginning of the year with the 7% to 8% range, but we received some tax refunds from the state of Oklahoma and from Texas, and now that we have that cash in the door, we expect that that will be a rate that goes forward. So, we were comfortable in decreasing that guidance.

And then for the Eagle Ford shale wells that you've already drilled, what are the average costs to complete, is it higher than $7 million that you said, putting in 95% IRR?

Yes, I can't -- I don't know exactly what it is but we spent some science dollars, and there was a learning curve issue early on, so the average cost of the wells we have drilled to date is probably higher. We took a full core on 1 well. So, all that stuff adds up. Going forward, routinely, we think $7 million is a good number.

And that decline is a partial driver for the decrease in the second half of the unit cost for LOE, a little bit higher than your guidance.

The primary driver in the drop of the LOE is the Eagle Ford volumes coming on. Since those are brand new wells and there's not a whole lot of LOE required, that is really the driver. If you look at our full company LOE average rate, the Eagle Ford wells are much lower. So, as we bring on those volumes that is driving our LOE lower in the second half. That, and selling the Arkoma assets, which were relatively high-cost LOE assets.

Great. That's it. Thanks.

(Operator Instructions)

Devin Goeghegan, Zimmer Lucas Partners.

Hi, thanks for the time today. I just wanted to clarify, you said the Colony Wash was $7.5 million or was that like Granite Wash prospects. I just, I didn't understand--.

No, that's Colony Wash, $7.5 million to $8 million.

Is that just general inflation or have you guys changed the design at all?

No, it's just, in some of the newer parts of the field, it's just some tougher stuff to drill. And the rotating days have increased substantially from the original wells we drilled. We used to use $6 million to $6.5 million. There has been some cost inflation with pumping charges, of course, and so there is a cost creep, but there has also been some operational issues that have also caused that cost to go up.

And that is for the 80 locations left, so, going forward, I should just use $7.5 million on the 80.

Can't say that in general. Some of the 80 locations would be, the penetration rates would be higher. This would be a swag, but I'd say if you want to use the higher cost for maybe half of them, I think that would probably be okay.

So like $8 million for a half and then kind of still use like $6.5 million for like half?

I would probably make that $7 million for the other half.

Okay, so $7.5 million is fair?

Yes.

And do you guys still plan to drill about 20 of those next year? On a gross basis, sorry?

I think it's just north of 20, gross. At least at this point in time.

Okay. Thanks very much for your time. Appreciate it.

Devon Xu, Wells Fargo.

I just had a question in terms of the future spending in 2012 to 2013. You said that you would have enough liquidity. Are you expecting significant increase in production? Or costs to come down? The financing and --

I'll answer the -- we have yet to set our 2012 budget, of course, but I would say considering that most of our programs, 75% to 80% of our programs are going to be focused on the Eagle Ford, and not knowing what's going to happen in Marcellus at this time, I would say our capital program would be in line with this year or maybe even less. There could be a case for it to be less if we just do Eagle Ford alone, if the Marcellus doesn't work, remembering that, again, I said earlier the Eagle Ford alone is not necessarily bad. We can grow the company at very attractive rates. [Capsular] wise and production increase wise with just an Eagle Ford alone program. But I would say it will probably be in the same ball park as what we experienced this year.

And you would be drawing revolver at that point?

Yes.

We would be drawing the revolver, in going into 2012, and just to follow up on with what Baird said, you mentioned that our program will probably be about the same or less, but we do expect our cash flow to be stronger next year because of the Eagle Ford component, and so we fell overall outspend therefore would be less than what you would expect this year. We would be [drawing] then on the revolver.

All right, thank you.

Eli Kantor, Jefferies and Company.

Good morning guys. In terms of the Eagle Ford leasing activity, what is the new lease price range you have in mind in looking at additional acreage and how quickly do you think you'll get up to 25,000?

Well, that is not an exact science kind of question or answer, but, you know, as I said earlier, the 6,000 per acre that we had used as limit, we can definitely justify increasing that substantially. If you look at our 500,000 barrel typical well and it generates $6.6 million of PV-10, you look at it on a per acre basis after tax, that is about $50,000 an acre. We never pay $50,000 an acre, but I think it sort of tells you what some of the stuff can be worth if you can find the right geological area. I'm sort of dancing around your question, I realize that, but, could you justify paying more than $10,000 an acre if you could find the right deal? The right acquisition? Yes.

There are some acquisition opportunities out there. You know, they continue to come on the market. They can be very competitive, of course. We can't afford to go out and to do a huge deal. But we can pick and choose and maybe find some things under the radar that make a lot of sense to us. There is still some grassroots leasing that we will continue to do. There are some options over time that will come up on people not being able to HBP their acreage, so some of this stuff is going to come back on the market here in the next year or so that we could go in and top lease as they refer to it on our business.

I can't tell you exactly where we get the 25,000 acres. I'd like to get there sooner than later. If I we can find the right acquisition to do it, we would do it, but it's still our goal to get to at least 25,000 acres by the end of the year. It's just going to cost us more money.

Okay. Thanks. In terms of Eagle Ford mid-stream, what is the capacity of the gas gathering you have in place and can you comment on potentially installing liquids rich or a liquids pipeline takeaway?

We have got -- I think right now, we've got about 9-and-a-half million a day on our mid-stream deal right now. We have the right to increase that, double it essentially over time, so we have more than enough room, we think, to handle our program, considering the gas at the end of the day is only about 8% of the total stream. Total product. As far as liquid takeaway -- when you start producing this much oil, it takes a lot of trucks to handle that on a daily basis. It's being handled right now through multiple purchasers through trucking alone, but we are looking at the pipeline, there's a couple of options we're looking at right now. I think we'd all feel comfortable in having a pipeline option in hand in 2012 or some point in time considering the serious ramp-up in total oil production, so I think you will probably see us at some point in time pull the trigger on committing to one of those 2 options.

Okay, thanks, Baird.

You're welcome.

Gentlemen, I'll turn the conference back to you for closing remarks.

Thank you very much, I realize that things haven't worked out exactly right with the reduction in guidance here. But we think we're on the right track and I can tell you the team here is probably as fired up as we have been on turning this thing around and really look forward to subsequent quarters and getting our story out. And with that, thank you very much.

That concludes today's conference, thank you all for joining us.