Ranger Oil Corp (ROCC) 2012 Q1 法說會逐字稿

Good day, and welcome to the Penn Virginia Corporation first quarter 2012 earnings conference call. Today's conference is being recorded. At this time, I am pleased to turn the conference over to Mr. Baird Whitehead. Please go ahead, sir.

Jennifer, thank you. Good morning, and I would like to welcome you to Penn Virginia first quarter 2012 conference call. I am joined by various members of our team today including Nancy Synder our Chief Administrative Officer; Steve Hartman our CFO ; John Brooks our Senior Vice President, and Regional Manager for Gulf Coast Operations; 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 statements of the press release as issued last night as well as a form 10-Q which will be filed today and which will apply to our comments this morning.

I would like to begin , first of an all, on a discussion by expanding on the earnings and operational update press release that was issued at the close of yesterday. We had a very good first quarter. The transition from the natural gas company to one that has an increase mix of liquids and gas continues. And overall the first quarter results demonstrate we were executing on that strategy. Before we get into the details of quarter, I wanted to touch on a number of the recent developments which are significant for the Company and this includes the successful redetermination of our borrowing base to a level equal to our prior commitment level of $300 million, which is the high end of our expectation. We are happy to have this behind us. We have launched the sale process of our Granite Wash and other Mid-Continent assets which we expect will help fund our capital program on spend of cash flow for this year.

We continue to have attractive results from our Eagle Ford drilling program, with an ongoing focus by our operating employees to decrease cost. They have done a great job in initiating incentive programs and fine tuning our completion to continue to drive these costs down. We have had the early results from Lavaca County Eagle Ford exploratory wells, which have either met or exceeded our expectations and provide us with significant additions to our drilling inventory and reserves overtime. We successfully completed our hedging goals from 2012 to 2014 at prices of at least $100 per barrel.

And lastly , we have affirmed production guides and raised EBITDAX and cash flow guidance for 2012 with record oil and gas, natural gas liquid production expected for the year, in spite of the our proposed sale of our Mid-Continent assets as the year goes on. Again, we had a good first quarter with much improved product revenue, EBITDAX and cash flows relative to our previous years quarter primarily due to a 192% increase in oil production ,which in turn , of course, is attributable to the ongoing growth of our Eagle Ford program. Steve will give you a lot more detail concerning our first quarter financials here in a few minutes.

Production was 10.9 Bcfe or 120 million a day which was 6% below production in the first quarter 2011 taking into account the sale of our Arkoma assets primarily due to a 31% less natural gas production and a decline associated with the decision to discontinue any natural gas drilling since the middle of 2010. That gas production decrease was partially offset by 90% increase in proforma oil and liquids production from approximately 400,000 barrels equivalent in the first quarter 2011 to 763,000 barrels equivalent in the first quarter of 2012. First quarter 2012 production was also 15% higher than the 662,000 barrels of total liquid production in the fourth quarter of 2011, so we continue to ramp things up. First quarter production was 42% oil and liquid as compared to 20% in the first quarter of 2011, and 37% in the fourth quarter 2011. We expect oil and natural gas liquid production to be about 43% of our total production.

Clearly the Eagle Ford Shale is driving our growth and we now plan to spend about 90% of our total capital on this play in 2012. Our results most of which have been drilled in volatile oil window Gonzales and Lavaca Counties have been very attractive. Along with a premium oil pricing we are getting since we sell in to the LLS market , as well as continued progress in lower cost we believe we have an excellent geological and acreage position within a leading domestic oil play that has been very acceptable returns that will provide ongoing growth in oil production for this Company. We have drilled 45 Eagle Ford wells to date , and have just turned in line the 44th well. The other well is waiting on completion. We now have 2 rigs drilling in Eagle Ford one of which is in Gonzales County on a rock creek lease where we have had excellent results to date and the other in Lavaca County on our third Lavaca County well.

Preprocessing our April production to date at the time this data was collected was about 11,000 barrels a day equivalent which is approximately 86%. This is preprocessing , this is not post processing. 40 of these 44 producing wells had an average peak rate of 1,000 barrels a day equivalent with a 30 day average rate of 645 barrels a day for the 35 applicable wells. 4 of the wells drilled to date are not include in this statistics due to shorter lateral primarily as a result of some geological issues. For the 40 longer length lateral wells we haveaverage lengths of about 3,800 feet and 15 frac stages.

In Lavaca County we have had good news the first two wells; the Effenberger and Vana wells are producing, and had 9 days and 5 days average gross rates of 922 barrels a day and 709 barrels a days equivalent respective. I want to point out these flow rates were at restricted rates with some high flowing pressures. You have to be careful when you compare IP of wells since you have to look at both the flow rates and flowing pressures. This flowing pressure essentially is a measure of restriction on a certain choke size.

In fact, the Effenberger well the first well we drilled the 922 barrel a day rate was with a flowing pressure of 3,450 pounds on a 1264 choke. We didn't yank on this well very hard clearly this well was capable of a much higher IP rate if we elected to do so. The second well the Vana well which had a shorter stimulated lateral due to an operational issue which tested with a flowing pressure of 2300 pounds. We are now drilling our third well and plan to drill 3 more wells during the balance of 2012 earning the 13,500 gross and about 8,000 net acres in this area of mutual interest.

The original risk going from Gonzales into Lavaca County was we were concerned, and we knew that there was an overall thinning of the high resistivity section that one typically looks for in this Eagle Ford pay and that is in fact where we drilled our lateral. This high resistivity section thins, but there was a lower resistivity section that develops and thickens as you go from west to east. This low resistivity portion of the shale could be interpreted to have a higher clay content or the other plausible explanation is there is a mineralogical issue that are suppresses the resistivity curve. If it is mineralogical in nature this lower resistivity section could actually be (Inaudible). We took some (Inaudible) in the Effenberger well and with their analysis and further drilling we will ultimately understand this geological attribute, but we do have the high resistivity part of the pay in these first couple of wells in fact even in the third well which we have drilled a pilot hole and we are drilling our lateral in this high resistivity pay, but in general we are very excited about what we have seen so far in Lavaca County.

One last thing about Lavaca County, and I think I mentioned this earlier on a conference call you would expect the gas oil ratio to increase, i.e. to get gas as you go to the east. The first 2 wells we drilled actually had gas oil ratios very similar to what we have seen in Gonzales County. The one thing that is unusual that we have seen is the higher pressures we are seeing in these first 2 wells. In fact they were high enough as we got into this year we have had to set an intermediate string of pipe through the Austin Chalk and drill the lateral with a much higher mud weight, much higher than we have in Gonzales County. So even though it is costing incremental dollars because of this other string of pipe, the good news is we have higher pressures.

A continued focus for our Eagle Ford program is to continue to reduce drilling completion costs. We have made significant progress in reducing our costs. Dropping from just over $10 million per well in the third quarter of 2011 to a little over $8 million in the fourth quarter of 2011 toapproximately $7.5 million in the first quarter of2012 . So the guys have done a very good job in getting our costs down. Much of this cost reduction continue to be on the completion side. We have reduced the size of each stage as to the amount of profit pump, and we have reduced the amount of ceramic that we are pumping. Where as today we are pumping about 50% white sand to 50% ceramic in each stage. Our initial wells in Lavaca County will be100% ceramic because we wanted to take that risk out of the interpretation we had, and because of the somewhat increased depth we think running the ceramic is the prudent thing to do. Ultimately we will probably spend anywhere from $8 million to $9 million in Lavaca County because of this additional string of pipe.

We now expect to drill 32 gross wells about 27 net wells during 2012 including our 6 exploratory wells in Lavaca County. As previously announced, we have reduce our 2012 capital expenditure program by going from 3 rigs to 2 rigs in the Eagle Ford Shale and this actually happened late in March. We have previously announce our first down spacing test on a 3 well pad which we saw no inference during simulation with these 3 wells. The four drilling program in Eagle Ford in both Gonzales and Lavaca County is to get any remaining acreage that is not HBP to HBP. After that time, we will come back in and start down spacing between these wells on the order of anywhere from 600 feet to 1,000 feet between lateral and anywhere from 60 to 90 acres spacing. It is ultimately these wells the shale is so tight we think this tighter spacing is the right to thing to do.

As pointed out in the press release with our current Gonzales County acreage and with a minimum expected working interest of about 57% in Lavaca County we ultimately to bring our acreage position to Eagle Ford to about 31,400 gross and 23,100 net. With down spacing we believe we have up to 200 well locations now which we have drilled 47 or are currently drilling.

Lastly , in the Mid-Continent in addition to select participations with Chesapeake as the operator on some Granite Wash wells although we are in the process of divesting these assets, we expect to test this exploratory well we have mentioned in the past probably by the middle of the year. It is called Viola line it is our ring link prospect that we have not disclosed the location of it at this time. It is oil. We have about 8,000 net acres . If it works , we have anywhere from 40 to 50 gross wells to drill. It is a fracture carbonate in which we drill horizontally.

With that, I would like to turn it over to Steve Hartman, and have him give you an update on our financial progress for the quarter.

Thanks , Baird. Good morning. I will start the financial overview with a view of the income statement and thenon to a short update on our liquidity hedging and finally a guidance update. Total revenues for the quarter were $84.4 million up 23% over the prior year quarter . This quarters result include a gain on sale of $756,000 related to the closing of our Marcellus Shale position in Butler and Armstrong County. We recorded a $3 million gain last quarter related to the same sell.

Total product revenues for the quarter were $82.7 million or $7.60 for Mcf equivalent. Revenue from oil and natural oil liquid sales was $67.8 million which was 82% of our total product revenue . This is more than double where our oil and natural gas liquids derived revenue was a year ago when we reported $26.5 million or 39% of total product revenue.

Our average realized oil price for the quarter was $107.05 per barrel, up from $88.37 per barrel in the prior year quarter, and $98.49 per barrel in the previous quarter. The higher realized oil pricing is due to higher WTI pricing, but also because we have been selling as much of our Eagle Ford oil derived oil as possible on the LOS market which tends to attract (Inaudible) pricing. We have been realizing $2 to $12 per barrel higher on the LOS market net of transportation since the beginning of the year , and currently we are seeing net realized prices around $12 above WTI pricing . Our NGL pricing for the quarter was $42.24 per barrel down from $45.46 in the prior year quarter. Realized natural gas prices were much lower at $2.37 per Mcf down from $4.23 in the prior year quarter. Hedges improved our realized GAAP price by $1.28 per Mcf for a realized price including hedges of $3.65 for the quarter. Our hedges decreased oil realized price by $0.20 per barrel.

Cash operating expenses decreased 11% or $3.5 million to $27.4 million for the quarter. This equates to $2.52 for Mcf on a equivalent basis compared to $2.54 in the prior year quarter. As Baird mentioned earlier these improvements came primarily from our efforts to lower lease operating expenses and G&A expenses and from lower production taxes. We have also seen improvement in our coststructure from the sale of our higher cost Anadarko Basin assets last year and the resulting G&A restructuring. The operating expense improvement was offset by higher gathering, processing , and transportation expenses which increased due to having to absorb some unused transportation at Appalachia and due to a one time prior period gathering adjustment in the quarter of approximately $600,000 or $0.5 and a half per Mcf.

Our gross operating margin which we define as total product revenue less direct cash operating expenses was $5.08 per Mcfe for quarter up 63% from the prior year period. This improvement in our cash operating margin was a direct result of the investment in the Eagle Ford Shale program, which had a gross operating margin by itself in the first quarter of almost $15 per Mcfe not including allocated G&A. For this reason in this natural gas pricing environment we have been less focused on total production growth and more focus on margin and cash flow growth. Adjusted EBITDAX which is a key driver of our liquidity was $64.2 million for the quarter up 46% from $44.1 million in the fourth quarter 2012despite the much lower natural gas price environment . This is our third consecutive quarter of adjusted EBITDAX over $60 million . Adjusted EBITDAX is a non-GAAP number and it is reconciled on page 11 of the release.

Continuing with the income statement expiration expense was $8 million for the quarter an improvement of the $21.6 million ascompared to the prior year quarter primarily due to the recording of $16.4 million in dry hole costs in the prior year quarter and due to lower unproved property amortization as we continue to move Eagle Ford's lease cost in the proved category. We also had lower G&G cost in the quarter. DD&A expense was $50.8 million or $4.67 per Mcfe for the quarter an increase of $16 million over the prior year quarter. The higher DD&A rate is primarily due to drilling higher F&D cost oil well in the Eagle Ford as compared with generally lower F&D cost natural gas wells, but the trade off for the higher F&D cost is higher economic returns and higher cash margins, so this is a trade off we are willing to make.

Our DD&A rate was also impacted negatively due to some negative reserve revisions at year end in some of the natural gas plays which resulted in higher gas depletion rates for 2012. Bottom line we reported a net loss for the quarter of $11.9 million or $0.26 per diluted share. Adjusting for the non cash impacts of hedging or other gains or losses that affect profitability between periods we reported an adjusted net loss $7.1 million or $0.15 per share . This is a $16 million improvement over the prior year quarter.

Moving on to capital resources and liquidity on page 6 of the release. At quarter end we had total debt of $724 million comprised of $600 million of high yield notes, $5 million of subordinated convertible notes, and $119 outstanding on our revolving credit facility. Our current revolver balance is $147 million . Giving us $151 million of availability on the revolver net of outstanding letters of credit. We have no debt maturities until 2016 other than $5 million convertible notes which are due in the fourth quarter this year. As Baird mentioned in his introduction our borrowing base was recently unanimously confirmed at $300 million to match our current commitment. We had been guiding investors on recent webcast presentation toward a borrowing base of $280 million to $300 million, but we are pleased our borrowing base came in at the upper end of the range. We expect to out spend cash flow in 2012, but expect to fund this gap with proceeds from our recently announced sale of Granite Wash which Baird describe earlier.

We have provided guidance for that projected out spend on page 6 of the release. Our current out spend guidance of $107.2 million to $147.2 million for the full year. We are guiding toward lower out spend by lower the upper bound of this range by $10 million from last quarter due to higher expected cash flows from operation. This guidance as well as our guidance on adjusted EBITDAX assumes a forward price for oil of $95 a barrel and $2.40 for natural gas. This also includes a $30 million federal income tax refund we expect to receive in the fourth quarter of this year, related to the sale of PVG plus some other assumed changes in working capital. To the extent the assets sale proceeds do not fully fund the spending gap we would fund the remainder with borrowings on the credit facility. Keep in mind these are full year guidance number any short fall that would need to be funded on the revolver would be added to our year end 2011 revolver balance of $99 million not our current out current outstanding balance.

Finally an update on hedging before moving on to guidance. We have been aggressively hedging our oil productions since the last earnings call. Adding 9 new positions cover 2012 to 2014 production. Our current hedge portfolio is summarize on page 13 of the release. We have approximately 70% of our oil hedge as percentage of the midpoint of guidance at a weighted average price of $102 per barrel. We have approximately 25% of our natural gas hedge also as a percentage of the midpoint of guidance at a weighted average price of $5.27 per Mcf.

Now on to guidance. Our 2012 guidance is mostly being reaffirmed at current levels with a few small exceptions that I will walk you through now. Guidance is summarized on page 12 of the release. If we are successful in selling our Mid-Continent assets we will give you a a revised guidance at that time. Total production guidance is being reaffirmed at 40 Bcfe to 43 Bcfe. Our oil guidance is increasing slightly by 2.5% comparing midpoints to 2100 to 2275 Mboe. We feel more comfortable with raising the lower end guidance through the initial strong results in Lavaca. We are decreasing the lower end of our natural guidance and reaffirming the upper end at a range of 23 Bcf to 24.4 Bcf. We are expanding the lower end of guidance due to rationalizing some of our lower performing wells, plus shut ins, and removing compressionwhich will probably impact production by about a 0.5 Bcf for the year.

Since this is very low margin production we would not expect this to impact cash margin and in fact may improve it. Our NGL guidance is reaffirmed at the same level. We expect our percentage of oil and NGL production will be slightly higher in 2012 at 42.5% at 43.3%. For production revenue we are tightening our guidance to $292 million to $316 million. We are narrowing the range due to the increase in our hedge oil production to 70% which is lowering the variability and realized price. We are decreasing our expected range for natural gas revenue due to weaker commodity prices, but that is more than offset with higher expected oil volumes and realized price. We now expect oil and NGL revenue to be between 83% and 85% of total product revenues up from 77% to 78% in our initial guidance.

We are reaffirming operating expenses and G&A in our previous guidance levels with the exception of a slight increase in gathering, processing, and transportation expense due to unused burnt capacity which has been difficult to sell in this gas environment. We are lower our guidance for unproven property amortization due to de-risking portions of our Lavaca County acreage. We are lowering the top end of the range of our DD&A expense guidancedue to lower cost experience in our Eagle Ford development program. Given higher expected oil production, higher expected realized oil prices after hedging , and flat operating expenses we are increasing our guidance slightly for adjusted EBITDAX to a range of $220 million to $240 million . Finally, we are reaffirming our capital expenditure guidance at $300 million to $325 million. Although we are seeing an improvement in our development of well cost as Baird explained earlier, we have some exploratory wells coming up whose costs are always difficult to predict. We are expecting a shift of $5 million in costs from drilling to pipeline and facility. Other than that we are comfortable with the ranges provided in February. That concludes the financial review.

Thanks, Steve. In closing I just want to say that this Company remains committed to a strong a flexible balance sheet . We have to have enough liquidity of course to position us to weather challenges, and take advantage of market opportunities that we see. And we continue to find market opportunities, includingbuying acreage in or around and adjacent to what we already have in Eagle Ford. We have made some decisions. We decided to slow down or Eagle Ford program going from 3 rigs to 2 rigs. We have suspended any and all natural gas drilling. Lastly we are selling some assets in the Mid-Continent to bolster our liquidity. Simultaneous

while we take these initiatives, we still feel we are in a good position to continue to increase oil production with Eagle Ford and hopefully with a success of (Inaudible) and at the same time continuing to increase our cash flows. Ultimately as is the case with many of our industry , we still remained leveraged to a recovery in natural gas prices, but the strategy at least in the near term is to stay focus and make the right decisions in this low gas price environment.

With that, Jennifer, we are ready to take any questions.

Thank you. (Operator Instructions). We will move first to Neal Dingmann with SunTrust .

Hi, guys.

Good morning.

Can you give us some color on your new acreage position in Viola, and your what you are expecting for your initial well cost and that part first.

Probably at the end of this second quarter we have about 8,000 net acres. We have not disclosed where acreage position is for competitive reasons. There is sufficient vertical well control to give us a lot of confidence we will find a well. The question is can you find it at sufficient economic quantities. It is a fracture carbonate play. We have the ability to add acreage. This first well will be more on the expensive side because of science data. We have a pilot hole to drill, collect some up hole information, come back and kick it off, and drill it horizontally.

I would expect our initial well to cost $5 million to $6 million ongoing after the fact I would say it probably more in line with a Mississippi and line kind of well of $3 million to $4 million per well. You should be able to save money on completion side because it is a fractured carbonate as opposed to a shale reservoir. That is how you would expect to keep you well costs on the lower side. Per well reserves were modestly estimated at about 200,000 barrels a little over 200,000 barrels per well. We have running room. I think we have around 40 gross locations. In any case I told you everything I know.

Excellent. I know you also mentioned if you couldn't fund your capital spend this year with the Granite Wash divestiture you would use your revolver facility. Are there any other levers you could possibly pull if you didn't want to go that route?

Steve, did you want to answer that question.

No, that would be the most attractive. We would have a $230 million commitment in borrowing base. We have $99 million outstanding on the revolver. It costs us about 2% a year in interest expense it is non dilutive. There would be no reason for us to go to any other source of capital at this time.

Right.

We will move forward to our next question which comes from Stephen Berman with Pritchard Capital Partners.

Good morning guys. Baird , on the divestiture. Is this something you are looking to sell as a package. Would you sale it piece meal if that was the best alternative. You gave some good detail there. One more question what are the capital expenditures associated with these assets in 2012 . I assume you haven't backed any numbers out of our guidance for this stuff.

Steve, the Granite Wash is the bulk of the value. We have some other wells. We have a good hunting well for instance in Norman. I guess if we received an offer for some wells we would consider breaking the package up. But at the end of the day the Granite Wash since this is is a fairly contingence piece is 90% to 95% of the value. As to the capital expenditure , if memory serves me correct, I think$25 million we had incorporated in our guidance for these assets to be sold.

Would you care to throw out any numbers for the kind of priceage you might be looking for or expecting.

We knew we were going to have this question and we have had a lot of discussion. The best way to do it is there is a teaser act in the market right now the 3P reserves is about $210 million that is a PV10.

The PV10 was a 3P. On the Viola line acreage is prospective for anything else besides the Viola line that might be of interest down the road.

It is, that is a good question. This carbonate section is extremely thick probably 1,000 to 2,000 thick. There are other tentatively other pays within this overall gross intervolve. We also have a deeper objective that we saw it is a very pronounced structure in the Arbuckle. We shot a 3D and identified this structure probably, John, correct me if I'm wrong, but 600 acres of 700 acres in size if memory serves me correct. It is sort of in the (Inaudible) that you expect to find some more Arbuckle. These would be bigger large reserve kind of wells, high rate kind of wells. So, yes, this is not just a one trick pony. This would have multiple pays.

Excellent that is it from me. Thanks, Baird.

Thank you, Steve.

Now we will take a question from Adam Leight with RBC Capital Markets.

Good morning.

Hello, Adam.

I guess I will try a little bit again on the evaluation of Granite Wash. How much if you can of that 210 is proved proportionately, how is that?

I prefer not to do that. The bulk of it would be the proved side, I will tell you that.

Okay. That is fine. Then on Viola line even at $3 million to $4 million a well 200,000 barrel EUR sounds light compared to a (Inaudible) well. Are the returns expected to be similar?

Based on our economic , if memory services me correct, I think we are talking at 25% to 30% after tax.

Does it need infrastructure water and things like that?

No, that is good point. Jim Dean is talking in my ear behind me. The water production on this stuff should be a lot less at least based on the vertical well control and production information we have. So you would not have the disposal and additional pipeline facility disposal well facilities associated with this play.

Is it also higher oil cut?

Yes. It would be extremely high oil cut based on what we have seen in vertical wells.

If I missed it , I apologize. Did you say what your HPP commitment is in the Eagle Ford area?.

John, help me out here. But if you include Gonzales County, I think we have 18 wells left to drill to HPP acreage. We have addition wells in Lavaca County as far as the (Inaudible) on top of that. But just to earn our back bone for our development program right now we have 18 wells.

And in the AMI, I guess it is early, but has your partner gave you any indication on whether they are going to back in?

They have yet to tell us what their plans are.

Okay. And lastly in the Eagle Ford, I am presuming perhaps wrongly, that you are seeing more services available less likelihood of bottleneck; is that a fair assumption?

John, answer that question.

Yes. With the exception of probably of drilling rigs everything else is readily available.

Okay. That is great thanks.

Thank you.

(Operator Instructions). Next we will take a question from David Amsellem with Howard Weil .

Hi guys, good morning.

Hi, David.

I just want to touch on your oil production guidance specifically. Can you talk a little bit more in detail about the assumptions you are making for the rest of year there? I am having trouble getting down to the lower growth rate that you are guiding to.

Well, we utilize a typically type curve to forecast these things . We also incorporate a risk factor incoming up with volumes. Just taking into account if anything happens, but really at the end of the day that is what it encompasses.

Okay. And what is the breakdown between Gonzales and Lavaca in the Eagle Ford in your model going forward?

If I am not mistaken, we have 3 more wells, we are drilling the third, we have 3 wells on top of that , so we have four wells yet to see any volumes for to date. And I think we just have those 4 with the budget and everything else is in Gonzales County.

Okay. And finally you noted the higher GOR as you go east in Lovaca. Can you describe generally how your acreage breaks down against that GOR gradient going east?

I can't give you a black and white answer. To be honest with you,I would have thought we would have seen some higher GORs in these first couple of wells we drilled, but we did not. They are acting almost the same as Gonzales County. As far as where we start to see higher GOR the first 3 wells are on a northeast southwest line. The second 3 wells will be probably east of that lined up also. I would expect we would see some higher GOR in these next 3 wells. John, I don't know if you have anything to add to that, but it is unknown an at this time?

Out of the first 6 wells that we have drilled or plan on drilling, probably 1 or 2 of those will be further downdip and the further downdip you go towards the coast is when you expect to see the higher GOR , but we haven't seen them yet . We have seen the higher pressure with similar Cortex oil production.

We are about 750 feet to 1,000 feet in what we see in --

About a 1,000 foot TVD.

So I would have expected to see some higher GOR. The good news is we have higher pressure which would infer you have higher reserves because of the higher pressure. Also the good thing is the economic should be improved because the status quo as far as how much oil we have which is 86% is going to hold true.

Okay. Thank you very much . That was very helpful. Thanks.

Now we will take a question from Biju Perincheril with Jefferies & Company.

Good morning.

Good morning. How are you?

Good. Congratulation on a very good quarter. Just a few questions. The Viola well that is horizontal; is that right?

We were drilling initially vertically to get the lay of the land and collect some science data, but, yes, we will ultimately take that vertical well plug back and drill it horizontally.

Got it. And that vertical hole will give you the information that you need to see where to land the lateral.

Exactly. We will run a FMI which is fracture identification kind of log and try to get some orientation of those fractures. We have a good sense of the orientation already, but the FMI will confirm that. After which we will get a turn around (Inaudible) and line up that lateral direction so it is perpendicular to those fractures.

I know you mentioned you expected to have less water here compare to the Mid line, but did you say what kind of oil you could expect or what are you planning for disposal wells in terms of how many disposals per producers or something like that?

I don't have a good handle on water cut at this time, but I would expect it probably going to be probably 80% plus oil. Is that a good estimate, John?

Yes.

Okay.

Perfect. On the Eagle Ford. The 8,000 acres that you earn what is the split between the high resistivity area and the low resistivity area?

We don't know for sure. As we drill wells it is going to help unlock that question. We have seen even in the third well we have seen a high resistivity part of overall section. We do know based on very limited well data , vertical data, if you get east of our acreage that high resistivity section goes away completely. And all you have is low resistivity. Does that mean it is not productive, that is a question wehave yet to completely answer. We think there is a good chance it is mineralogy related , i.e. pyrite, which will suppress a resistivity curve. We have seen it in the samples. I can't tell you exactly where we go from no high resistivity to all low resistivity.

Okay. And that area on the east side is that something you plan to test. Do you have to drill a well to see if that area works, and do you have any plans in the near term to do that?

Yes, we do need to drill it to see if it works. We need to get these next 3 wells drilled, get the (Inaudible) We willstep out either late this year or early next year and get a lay of the land sooner than later so we can use it for planning purposes.

Perfect. And then one last question. What is your well cost down in Gonzales County area?

About $7.5 million in the first quarter.

Great. And it was about $8.5 million you were running before that.

In the fourth quarter we were just north of $8 million , $8.3 millionto be exact.

Okay. Great, thank you very much.

Thank you, BJ.

We will now take a question from Richard Tullis from Capital One Southcoast.

Thank you, good morning.

Hi, Richard.

Just a couple of questions.

Did you , Baird, provide a time line or expect a time line for announcement on the potential assets sale ? when you think you may have something?

I think the guidance we provided probably early third quarter.

Okay. Announcement possibly by early 3Q.

Yes.

What about the Appalachia assets any plans to do anything with those? Is it just too difficult to sell those kind of gas assets in this type of environment?

At this time it is status quo we looked at all option in deciding what to sell. Gas assets in this market didn't make any sense for us at all. It didn't take care of the out spend issue in general. So the Mid-Con had a much less execution risk , so we decided to pick that assets for that reason.

Okay. What could be the potential impact on your borrowing base from the Mid-Con sale? Have you guys worked through that yet?

It should be about $70 million.

$70 million lower versus where it is now?

Yes. At the same time you have to remember we are continuing to drill Eagle Ford well which adds borrowing base quickly.

Right. I know you mentioned a little earlier the estimated drilling locations in Eagle Ford roughly around 200 including what you have already drilled I guess that is gross; is that correct?

That is correct.

What is your net number , Baird?

I have to give you (Inaudible). If you took 70% of that which would be a mix between Lavaca County, I am making the assumption that (Inaudible) would participate. I would say a pretty good mix.

Okay. That is fine. And then just lastly, the Cotton Valley horizontals . I know you guys don't have much pray in there right now , but how can those rates of return based on your assumptions stack up versus what you are seeing in the Eagle Ford?

They are lower. I think the last time we looked at, which was not too long ago, were probably 15% to 20% after tax. It does have a high liquid component both well head oil and NGLs. The problem with that play is the cost side. We think we can probably get these things drilled for around $6.5 million to $7 million . It is just because you have all these shallow depleted sands, and you have to get this stuff cased off in order to drill it horizontally.

Where as if you are just drilling horizontally in Cotton Valley you can sort of fight your way through it and not have to set an intermediate string of pipe. But that is the issue. Plus trying to drill this stuff horizontally in Cotton Valley it is hard drilling, tough drilling. You go through some PDC bits even though there has been a lot of progress made in PDCs and drilling hard formation. It is just tough stuff to drill. So that is a long answer for a short question. It wouldn't take a lot of gas price increase for us to get excited about it again.

Okay , that is fair enough. All right. Well, thanks a bunch , Baird. I appreciate it.

No, problem. Thank you , Richard.

Now a question from David Snow with Energy Equities Incorporated .

Hi. What is the back end assumption or the right to your acreage in Eagle Ford and what could your upside be if they don't backend?

Well, guys, we had no backend.

The 8,000 acres.

Go ahead.

The partner that has executed that agreement with us has the option to participate at 40% in the development wells.

So if they decide not to go forward, we would have about 93%, John? We have about 7% worth of partners, smaller partners. Right now 57 % is our working interest.

97.

Excuse me , it a high number.

I think every indication is that if you are successful they will join you on the development wells, I guess.

We think so. They are not stupid , of course, with a couple of well qualities -- the qualities of the wells we have seen to date I would suspect they will probably go with us.

I thought, if I remember right, Granite Wash had your highest rate of return 100% or something like that, and you mentioned after tax 25% or 30%. Would it not make sense to hold the higher rate of return and forego the lower rate of return, or what it is the thinking of that?

Actually , the Granite Wash wells, the rate of returns of those wells have come way down, David. The 100% we had was a pre down spacing kind of number at a well cost. It was around $5.5 million to $6 million. Because of the communication issue we have had , we have had to bring the reserves of those wells down to about 4 Bcf . And the cost of those wells have got up to $7.5 millionto $8 million . So the rate of returns on those Granite Wash wells today are about 20%.

Okay . All right. What are you thinking your EUR might be in the Eagle Ford on average from these terrific wells.

It depends on -- anywhere from 300,000 barrels to 400,000 barrels. We think around 400,000 barrels, because of terminal decline issues. You can make the case it may be nice to be 320,000 barrels, but at the end of the day it doesn't affect the economics. The economics are the same.

Are you near the AOG part of this play?

We are pretty close to them.

So you should have similar economics to them and EURs?

Well, they have some excellent wells in (Inaudible) County. I would say their (Inaudible) County sweet spot is a step above what we have. But what we have, we think it is very good.

Terrific. Thank you very ,very much.

Thanks, David.

And our final question will come from [Sean Sneeden] with Oppenheimer.

Thank you for taking the question.

Hi , Sean.

Just going back to the Granite Wash assets sell. I think you said that the liquid content there has been in the mid to high 40s there.

That is correct.

Right. If I remember correctly , you operate one-third of the assets with I think you said Chesapeake operates the other two-thirds there?

That is correct.

Can you talk about how that portion might fit into your discussions with potential buyers, and similarly have you had any discussions with Chesapeake on acreage?

I don't have an answer for your question. Chesapeake is the other owner . They have most of those assets in a drilling trust. They have a rig running right now . They are operating on these assets, and really that is it.

Okay. I guess what I was trying to get at was would you ever try to package this deal. Obviously, Chesapeake has a decent amount of money they need to raise themselves. Would you ever partner with them and sell the whole thing?

That is always an option. We have not contacted Chesapeake or visa versa. Since it is in a drilling trust it makes it more problematic on those guys buying those assets. We have not had any discussions with them.

Okay. Fair enough. And then it sounds like your CapEx plans are relatively funded whether through an assets sale or through the revolver this year. It sounds like a lot of people have been focusing on what 2013 might look like. Can you help us understand what you might look to spend on Eagle Ford next year?

As far as our plans in Eagle Ford next year?

Right. Yes.

It is yet to be defined. We may stick with the 2 rigs. We may decide to go to 3 rigs. We have not decided for sure.

Okay .Fair enough. Thank you.

Your welcome. Thank you Shawn.

At this time that does conclude the question-and-answer session for today. At this time , I will go ahead and turn the call back over to Mr. Whiteheadfor any additional or closing remarks.

Well, thank you for listening in. We are very happy as you would expect with our first quarter results , and it is our plan to stay focused and keep moving ahead. Thank you very much.

Thank you, sir. That does conclude today's teleconference. We do thank you all for your participation.