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Executives

Baird Whitehead - Chief Executive Officer

Nancy Snyder - Chief Administrative Officer

Steve Hartman - Chief Financial Officer

John Brooks - Senior Vice President & Regional Manager

Jim Dean - Vice President of Corporate Development

Analysts

Neal Dingmann - SunTrust

Scott Hanold - RBC Capital Markets

Amir Arif - Stifel Nicolaus

Welles Fitzpatrick - Johnson Rice

Adam Leight - RBC Capital Markets

Penn Virginia Corporation (PVA) Q3 2012 Earnings Call November 1, 2012 10:00 AM ET

Operator

Good day everyone and welcome to the Penn Virginia Corporation, third quarter 2012 earnings conference call. Today’s conference is being recorded.

At this time, I would like to turn the conference over to the Baird Whitehead, Chief Executive Officer. Please go ahead sir.

Baird Whitehead

Thank you very much Jenny. Good morning and welcome to Penn Virginia’s third quarter conference call. I am joined today by various members of our team, including Nancy Snyder, our Chief Administrative Officer; Steve Hartman, our CFO; John Brooks, our Senior Vice President and Regional Manager; and Jim Dean, our Vice President of Corporate Development.

Prior to getting started, we would like to remind everyone that the language in our forward-looking statement sections of the press release was issued last night, as well as our Form 10-Q, which will be filed very soon, will apply to our comments this morning.

We’d like to begin our discussion by expanding on the earnings and operational update, press release that was issued after the close yesterday.

The third quarter 2012 continued a trend of solid financial results, achieving our fifth consequently quarter or $60 million of EBITDAX or greater, with year-over-year increases in oil and natural gas liquid revenues and gross operating margins. We also continued to drill what we consider a very good Eagle Ford wells and simultaneously continue to de-risk our Lavaca County acreage. We have also recently added a third rig in this Eagle Ford play.

Before we get to the details of the quarter I wanted to touch on a number of recent developments, which we think our significant for Penn Virginia’s primary goals of continuing to grow our oil inventory and simultaneous strengthening our balance sheet and liquidity.

First of all, since our second quarter in which we announced the closing of a $100 million sales of our Appalachian assets and the elimination of our common dividend, we’ve also put in place a new credit facility of $300 million with a borrowing base that is $30 million higher than the previous credit facility, along with more favorable covenants at similar pricing.

Secondly, we raised $155 million of net proceeds through the issuance of 9.2 million shares of common stock and $115 million for preferred equity. All of these steps have greatly improved our balance sheet and liquidity with today an unused credit facility and approximately $50 million of cash on hand. These sources of liquidity along with expected cash flows for 2013 are expected to fully fund our capital expenditure program for 2013.

Finally, we continue to experience solid results from our ongoing Eagle Ford drilling program, both in Gonzales and Lavaca County’s and recently increased our net acreage position in this play to approximately 30,000 net acres from a previous 25,000 net acres. We now believe conservatively that we have up to 285 remaining drilling locations with a six plus year inventory for our three-rig program.

Quarter-over-quarter and even though our production declined about 1.7 bcfe, primarily due to the sale of Appalachia and natural gas declines, adjusted EBITDAX was $61.2 million for the third quarter versus $60 million for the second quarter. This was due to total product revenue, which was essentially unchanged at $76 million, along with decreasing lease-operating cost quarter-over-quarter of about $3.1 million. This reduction in lease-operating cost was primarily associated with the sale of our Appalachian assets, which were our higher operating cost assets.

Third quarter EBITDAX was 8% less than the prior year’s $66 million due to reduced natural gas prices and natural gas production, resulting from the sales of Arkoma and the Appalachian assets in 2011 and 2012. Just to remind everyone, we also had received a one-time settle to unwind and interest rate swap in the third quarter of last year of about $3 million.

Our gross operating margin per mcfe remains strong, increasing 20% from $4.72 per mcfe in the prior year quarter to $5.68 per mcfe in the third quarter of this year, due to this ongoing shift to oil and natural gas liquids, as well as focus on lowering our operating cost.

Production of 9 bcfe or $98 million a day was 9% below production in the third quarter, again taking into account the sales of our Appalachian and Arkoma assets. This was primarily due to 31% less natural gas production, which was as you know due to the fact that we have eliminated any natural gas drilling, other than a few limited Granite Wash program wells over the last couple of years.

The decrease in pro forma natural gas production was partially offset by a 20% increase in oil and liquids production from approximately 649,000 barrels in the third quarter of 2011 to about 776,000 barrels in the third quarter 2012. So do oil and natural gas liquids productions of the 776,000 barrels was 3% lower than the 799,000 barrels of oil in the second quarter of this year, due primarily to 11% sequential decline in NGL production, as a result of some ethane rejection associated with this lower price, that being in a mid-continent, as well as lower Granite Wash natural gas production that is also processed.

Third quarter production was 52% oil and natural gas liquids as compared to the 33% number in the second quarter of 2011 and 45% in the second quarter of this year. Now for all of 2012 we expect oil and natural gas liquid production to be approximately 47% of our total production.

As you know the Eagle Ford Shale is the focus of our growth during 2012 as we plan to spend almost 90% of our total CapEx in this play. Our overall results remain excellent and have on average very attractive economics. Along with the premium oil pricing we are receiving since we sell into the LLS market, as well as continued emphasis on lowering our operating cost, we believe that we have a very strategic acreage position in this play, which we consider a leading domestic oil shale play.

In addition our drilling acreage position in Gonzales and Lavaca County’s puts us in a position to demonstrate ongoing oil growth. 59 Eagle Ford wells are producing with the 60th well currently being completed. Three rigs are currently drilling, two of which are in Lavaca County, the other in Gonzales County. Results for the recent wells drilled and completed were detailed in our press release.

First processing our gross Eagle Ford production for the quarter was about 6,300 bet barrels of oil equivalence per day we saw for the quarter, averaged by the 84% oil, 9% natural gas liquids and 7% residue gas. We expect the Eagle Ford production to decline slightly in the fourth quarter due to reduced rate count in the second and third quarters, but also expect to resume growth later this year into 2013 as the benefit of adding a third rig late in the third quarter begins to be realized.

We continue to feel confident with our 410,000 barrel of reserve internal type curve with Gonzales County based on the average take rate of 986 barrels of oil equivalent per day to the optical wells and a 30 day average of 656 barrels of oil equivalent per day. Some of the producing wells are not included in these statistics because of shorter laterals and of course lesser frac spaces. For the 49 full-length wells we have drilled and completed, we’ve averaged lateral lengths of about 3,900 feet in 16 frac stages.

Results in Lavaca County and our farm out acreage continue to meet our expectations with an average initial potential of 829 barrels of oil equivalent per day for the seven wells and that by the way is with significant back pressure is and average 30 day rates for the applicable five wells are 678 barrels of oil equivalent per day. The IPs are a little less than what we see in Gonzales County due to the significant amount of back pressure we owed, but at the same time the 30 day rates are a little more.

While the initial potential results are meeting expectations, the percent of Lavaca County acres that will be productive is exceeding original expectations. We just completed the furthest down-dip well named the Lia (Ph) well and is flowing back as we speak. We have not yet established an IP, but is currently flowing at an instantaneous rate of about 600 barrels of oil a day and about 1.2 million a day, this is well hit by the way, with a 3,900 flowing pressure and its very, very early in its clean up process, so that in itself tells us we have a good well here.

With results like this in fact we’ve gathered very convincing information from pilot holes, that has identified additional pay within the Eagle Ford section, we feel pretty confident at this time that our entire acreage position in Lavaca County will be productive and of course this is very good news considering we only valued originally about half of the acreage.

Steve in a minute will give you some guidance information with preliminary CapEx for 2013. This guidance assumes that a large partner will participate in those Lavaca County wells planned for 2013. It is expected that we will understand our partner’s intent across the entire acreage position by early in the second quarter next year. If they continue to go at 9% through the remaining initial unit wells, which are about 700 acres in size, at that time it would be our intent to go out and find a partner. It is not our intent to absorb these additional drilling completion costs over the longer term.

We also continue to make operational progress in drilling these wells and keep chipping away at the cost. We have moved to pumping only high strength white sand as proppant in Gonzales County and have gone to a mix of high strength white sand of ceramic in Lavaca County, whereas we have previously pumped only ceramic in Lavaca County. These steps have reduced our cost. We are now self sourcing not only our asset and proppant, but also now the guar. The guar itself by self-sourcing it saved us about $300,000 to $400,000 per well.

We also are now in general drilling the longer laterals, especially in Lavaca County where the drilling unit configurations allow us to do so. These longer laterals increase our individual well cost, primarily due to the increases in frac stages, but also may we think will increase the reserves on a per well basis and therefore our overall economics. And recently we added a pioneer rig, which has accelerated our drilling inventory in the play.

Just recently on the last well the pioneer drilled for us, we drilled that well in Gonzales County with a measured depth of almost 14,500 feet and a lateral length of about 4,800 feet in just a little over 11 days. This is a new record for us. This is about a week less than what we typically expect to drill wells in this step and lateral length in Gonzales County. Clearly this rig has taken us to the new level of efficiency on the drilling side.

Going forward, for planning purposes we expect to drill a well in Gonzales County for $7 million to $8 million and a well in Lavaca County for $8.5 million to $9.5 million. To remind everyone, the wells are deeper in Lavaca County, which requires an extra string of pipe, higher mud ways to drill and higher strength profits, but we also think the wells in Lavaca County will ultimately have high reserves than what we see in Gonzales County and therefore comparable economics.

We expect to drill 33 gross Eagle Ford wells this year, 26 net and we will likely drill anywhere from 35 to 40 Eagle Ford wells in 2013 assuming there’s a three-rig program. As spotted out in the release, our acreage position in the Eagle Ford is now approximately 40,000 gross, 30,000 net acres. With down spacing and continued success in Lavaca County, we believe that we now have up to 285 drilling locations, up from about 200 drilling locations at the end of the second quarter.

The stated goal of ours is at a minimum maintaining a six-year inventory by acquiring 4,000 to 5,000 bolt on net acres annually of anywhere to cost from $10 million to $20 million. In over the past two years we’ve been able to demonstrate that we can do this. This 4,000 to 5,000 net acre position will essentially replace the 35 to 40 net wells that we expect to drill annually with this three-rig program and we feel confident over the next few years that we can maintain this drilling inventory of 285 locations and we think this 285 locations is more than adequate in the near term.

We believe this inventory is adequate for two reasons; number one, we want to maintain this fiscal discipline and grow our cash flow so we can ultimately self-fund our capital program of $300 million to $325 million per year associated with our three-rig program. We feel that we can do that going into 2015 with the annual off spends decreasing up until then.

Number two, we think that the current inventory at 285 locations will increase on our existing acreage as we de-risk more of our Lavaca County acreage and include more down spaced wells. We have not been overly aggressive in identifying the current locations and I also want to point out these 285 locations are all on the map with a surface location, a bottom hole location and therefore a planned lateral length. These are not just mathematically derived locations based on some spacing assumption.

But having said all that, it is a focus of ours to continue to increase our inventory, either in Eagle Ford itself or in another self-generated new oil idea that ultimately will be drilled and proves to be successful.

In the Mid-Continent we continue to selectively participate on a non-operative basis in our Granite Wash. Also as we discussed in our release, we had some operational issues with our Viola Lime test well, we were only able to stimulate about 1,100 feet of a planned 4,100 feet lateral. We decided to go ahead and complete the well as it is, because we though that it would give us the answer we were looking for, but it only testing about 10 barrels of oil a day, which of course did not meet our expectations.

This prospect is being reevaluated with the possibility of drilling an additional well in 2013 to further test the prospect or attempting a re-completion up hold in a vertical well, in which we had a good mud log shows in the existing well. This up hold interval could also maybe a new horizontal target depending on the completion of results.

So with that, I’d like to go ahead and turn this over to Steve, so he can give you an update of our financial progress in the quarter.

Steve Hartman

Thanks Baird and good morning. I’ll start with the brief financial review. Product revenues were $76 million, down 8% from the prior year quarter, primarily due to a 46% decrease in gas production, which was primarily a result of the Appalachian Basin sale and a 36% decrease in natural gas pricing. This was offset by a 34% increase in oil volumes and a 14% increase in oil prices.

In an equivalent basis, we realized $8.37 per Mcfe in product revenue this quarter, which is 22% higher than the prior year quarter. Hedges added $8.08 per barrel to our realized oil price and $1.05 per Mcf to our natural gas price. As a side note, our reported product revenue does not include cash hedge settlement, which were $9.2 million this quarter.

Oil and NGL revenues were $64 million or 84% of total product revenues, an increase of 33% over the prior year quarter. Operating expenses decreased 5% or $1.3 million to $24.3 million or $2.69 per Mcfe. This is detailed in the release, but we saw significant improvements in lease operating expense and G&A expense.

Our lease operating expense improved 27%over the prior year quarter, due primarily to lower repair and maintenance cost, lower compression charges and lower water disposal cost. The Appalachian Basin assets were relatively higher costs for us, so not having those expenses after July 31 is also improving our performance.

G&A improved 4% over the prior year quarter, primarily due to closing two offices and centralizing functions to Houston and Radnor, and lower employee headcount. We recorded $1.4 million for restructuring this quarter primarily due to closing our Pittsburgh office.

Our adjusted net loss was $7 million for the quarter, which is a $0.16 per adjusted EPS. Adjusted net loss excludes non-cash chargers and derivatives, impairments, restructuring cost and other one-time cost. This compares to a $6.7 million adjusted net loss in the prior year quarter. Our reported net loss was $32.6 million, which includes a $17.3 million charge related to our firm transportation commitment in Appalachia related to the sale.

Cash flow from operating activities was $74 million this quarter, up from $39 million in the prior year quarter. The increase was primarily driven by the $32 million tax refund we received. This is still a good trend however. For the first nine months of the year we have received $190 million in cash flow compared to $103 million in the prior year period, which is an increase of 82%.

Our capital expenditures this quarter were $85 million, down from $114 million in the prior year quarter. Year-to-date we have spent $267 million, 88% of which was spent on drilling and completion and 90% or more of which was invested in the Eagle Ford.

Moving on to capital resources and liquidity, as Baird discussed earlier we’ve been working hard since our last earnings call to shore up on liquidity and pre fund the 2013-drilling program. In the last few months we have raised a $155 million net in the common and convertible preferred equity offerings.

We closed on the Appalachian Basin sale, raising about a $100 million, and received a $32 million tax refund. We also refinanced our credit facility, increasing our borrowing base by $70 million and we eliminated our dividend saving about $10 million annually. Altogether we have raised about $285 million of non-debt capital and increased our liquidity by over $350 million.

At quarter end we had total debt of $682 million, consisting of 600 million of high yield notes, 5 million of subordinated convertible notes and $77 million outstanding our credit facility. Currently after receiving the $155 million of net proceeds from the common and convertible preferred offerings, we have no debt outstanding on the credit facility and about $50 million of cash on hand. The subordinated convertible notes mature on November 15, and we expect to retire those notes with cash on hand and we have no further debt maturities until 2016.

Our new credit facility has a $300 million borrowing base, which increases our liquidity by $70 million over the previous facility. We extended the 4.5 times leverage covenant through the end of 2013, where at that point steps down to 4.25 for the first of 2014 and four times thereafter. We also extend the maturity of the credit facility to 2017. This refinancing services as our fall borrowing base re-determination, so we will not have another re-determination of our borrowing base until April of next year.

Our leverage, which is total debt divided by adjusted EBITDAX was 2.7 at the end of the quarter, pro forma for the offerings is 2.1 at quarter end and currently as of today, its around 2.3 times. As a result of the improvement in our balance sheet, S&P upgraded our credit rating from single B with negative outlook to single B with positive outlook and Moody’s is reviewing our rating as we speak.

Moving on to hedging, we added three natural gas hedges recently for calendar year 2013. $10 million cubic feet per day were hedged using a consult collar with $3.50 floors and $4.30 caps. 5 million a day were headed using a swap at $4.04. We did not add any oil hedges this quarter, but we are well hedged at this point, so we can afford to be patient with pricing.

For the balance of 2012, we have 68% of oil hedged as a percentage of the mid-point of guidance, with weighted average floors and caps of $100.80 by $102.55. Our natural gas hedge position for that same time period as of 25% hedged with a weighted average swap price of $5.24.

For 2013 we have about a third of our anticipated volumes of oil and natural gas hedged. Our oil is hedged at about a $100 a barrel weight averaged, and our natural gas is hedged by our recent trades I just mentioned. Our hedges provided $9.2 million of cash proceeds this quarter and have provided $24.2 million year-to-date. Our current hedge portfolio is summarized on page 12 of the release.

Now on the guidance for 2012, total production guidance is now 38.4 Bcfe to 38.9 Bcfe, which is a slight increase to the mid point of our previous guidance. This implies production for the fourth quarter of 7.9 Bcfe to 8.3 Bcfe. We are being a little conservative with our fourth quarter production because of timing of well completions, which are more heavily weighted toward the second half of the quarter.

We are increasing our oil guidance to 2.22 million to 2.25 million barrels. This implies fourth quarter oil product of 527,000 to 557,000 barrels. This is lower production than the third quarter as Baird explained earlier, but it a 24% increase over the fourth quarter of 2011.

We expect the volumes related to the third rig will start to add meaningfully in the first quarter 2013, and we expect to resume quarterly growth again with the three-rig program after that.

For production revenue, we are now forecasting $284 million to $303 million. This is $11 million increase from the mid-pint of our previous guidance. The increase in primarily due to better than anticipated results in the third quarter and continued strong realizations that we received by selling in the LLS market.

For LOE we are guiding towards slight improvement of $0.02 per Mcfe, building on the improvements we’ve already discussed. Same with G&A, we expect continuing improvements, so we are lowering the mid-point of our guidance by $0.05 pre Mcfe for recurring cash G&A.

Restructuring charges are mostly complete, so our guidance for that expense is now $1.2 million lower that our previous guidance. We are raising the mid-point of our guidance for adjusted EBITDAX by $5 million to a range of $235 million to $245 million. This implies fourth quarter EBITDAX of $50 million to $60 million and this is based on a price assumption of $90 for oil, $31.50 for NGL, $3.51 for natural gas and a plus $14 differential between the WTI and LLS market, which would yield us about a $6 realized price over WTI, net of transportation.

We are raising our capital expenditures guidance to a range of $338 million to $350 million. Land is up $10 million due to the acreage acquisitions we announced earlier this month. Drilling and completion expenditures are up $16 million due to our partner going non-consent in four wells in the Lavaca County as Baird already described.

Our current guidance assumes they will participate in future wells since the results have been good. If they do not however, we could have as much as $14 million of additional capital in 2012 to pick up their working interest. But keep in mid that this is a good outcome for us. These are excrement wells and if our partner goes non-consent, we pick up about 250 net acres for each drilling block they elect out of for no additional land capital.

For 2013 guidance, we are providing production guidance of 34 Bcfe to 37 Bcfe as compared to 34 bcfe for 2012, pro forma for the Appalachian Basin sale. We expect 2013 oil production will be approximate 2.7 million to 2.8 million barrels or about a 25% increase over the midpoint of 2012 oil production. We expect oil and NGO production together will be 55% to 65% of total production.

We will continue to operate a three-rig program in the Eagle Ford and concentrate nearly a 100% of investment in oil and NGO rich plays, primarily within the existing Eagle Ford acreage. Our anticipated capital program is $310 million to $345 million. We expect our cash outspend for 2013 will be around $125 million to $150 million with this type of a program.

Again, this plan assumes that our partner will participate in the 2013 Lavaca County program. If our partner goes non-consent for all the wells in 2013, we would have about approximately $60 million of additional capital in the plan for the extra 40% working interest, but if this happens as Baird mentions, we would expect that we would get a partner, and we should know the full extent of their participation by the second quarter 2013.

As I mentioned earlier, the 2013 program is fully funded at this point. Just to put this in context, we ended 2011 with around $100 million outstanding on our credit facility and if you assume the mid-point of the outspend guidance I just provided, we had 2013 which is slightly above a $100 million outstanding on the credit facility. So the capital we’ve raised over the last few months together with increasing cash flow from operations, that’s funding two years of the drilling program without adding any additional debts to the balance sheet.

Baird, that concludes guidance review.

Baird Whitehead

Thanks Steve. Just to wrap things up, I hope that you are seeing that this company is making progress. Even though it’s been painful, we made a lot of progress in this third quarter. We strengthened our balance sheet and we therefore improved our financial liquidity.

We’ve taken out risk off the table, which we thought was important to do going into 2013 and we think we are now well positioned to fund our future growth. This, along with fiscal discipline going forward, will allow us growth to a position that we think we can self fund those capital programs by 2015 and I can tell you that we are committed to making this goal.

With that Jenny, we are more than happy to take any questions.

Question-and-Answer Session

Operator

Thank you sir. (Operator Instructions). And we will go first to Neal Dingmann with SunTrust.

Neal Dingmann - SunTrust

Good morning guys, great color today. Baird, just a quick question on now the Lavaca success that you had there. Are you still going to delineate or you said now you think most of those wells on that area is perspective. Can you talk a little bit about that entire 30,000 acres now, what’s sort of the plan?

Baird Whitehead

Well, talking about Lavaca County specifically, with this Lia (ph) well, which is the furthest entity of where we have drilled in Lavaca County, we think with that and based on these pilot holes we have drilled, we’ve actually moved the productive limit of Lavaca County acreage all the way to the east and all the way to the extremity of our acreage. So having said that, we think Lavaca Country acreage at this point in time, the 13,000 gross acres is productive.

Everything up in Gonzales County we feel is productive. The only acreage that we’ve got somewhat of an unknown on is our acreage that is sort of the furthest west and it gets up into this earlier part of the window. The couple of wells we have drilled there have lesser IPs, but the one thing that we have also find out, they have much less of a clause associated with that.

So the plan is to get back up there and drill a few wells to get that acreage fully understood and drill some longer laterals, which we think untimely will improve the economics. So I guess at the end of the day we feel pretty good about our entire 30,000 net acreage position.

Neal Dingmann - SunTrust

Okay and then continuing on that Gonzales part, what’s your thought for potential for Pearsall in that plan? I think for a while you were talking about drilling one? I think you maybe haven’t. Just thoughts on that or going forward your activity going after Pearsall.

Baird Whitehead

Well, we’ve been testing not to talk about the Pearsall, just because we did drill a pilot hole two or three months ago, gathered some science information, took some sidewalk cores. Based on it, we do plan on spuding a Pearsall horizontal well later this year, probably the results will not be know until the beginning of next year, but it is our plan to test a Pearsall on or acreage.

We do think that probably out of the 30,000 acreage we have, probably 20,000 of that 30,000 would be in the volatile oil window. The stuff in Lavaca County in all practicality is probably too deep and too gassy.

But aside having said all that, there is not a lot of data of our rig, because the play has primarily been in the southwest part of the trend. EOG has drilled some of the wells; that plan has come toward us, but we will know lot more about the play first quarter next year.

Neal Dingmann - SunTrust

Great color, thanks Baird.

Baird Whitehead

All right, thanks.

Operator

And we will hear next from Scott Hanold with RBC Capital Markets.

Scott Hanold - RBC Capital Markets

Good morning.

Baird Whitehead

Hey Scott.

Scott Hanold - RBC Capital Markets

Hey. When looking in the next year you obvious talked about your partner up in sort of the Lavaca County area does not – to participate you’d be looking to find a partner and can you talk about why you wouldn’t just take the higher working interest and maybe reduce your drilling count as a replacement. Because you obviously are looking to add acreage to keep building your inventory, but in other words it just takes a higher working interest, which I think would tend to be sort of sometimes a better capital return proposition.

Baird Whitehead

Well, that clearly is an option and that’s something that we would consider. The issue that we’ve all got to rationalize is and John Brooks can speak to it probably better than I can. These wells are challenging to drill. They are expensive. You got the higher pressures. Not had anything bad happen on any of these wells, but having said that if you had a train wreck on one of these wells it could be a very costly train wreck and 8.5 to 9.5 depending on lateral length and even approaching $10 million on of these things, with a 96% interest, if a partner goes non-consent, its just very difficult for us to take on that additional risk.

We think that it will be easy to bring a partner in. We could leverage our knowledge. It would actually because of a promote that we would expect to receive on this acreage once we de-risked it, we think the promote will be attractive. At the end of the day with some kind cash and carry, and at the same time we want to maintain this fiscal discipline, we think that might be the better route to go.

But to this point in time, we can’t speak out both sides for a month and say we are going to spend a lot more money and drill these wells, but at the end of day it’s the operational risk that gives us some pause.

Scott Hanold - RBC Capital Markets

Okay, so diversification is the key part of that.

Baird Whitehead

Exactly, that’s exactly right.

Scott Hanold - RBC Capital Markets

And then as you look into 2013, how many wells of your – I think you said 35 wells you could drill next year. How many of those are going to be Lavaca versus Gonzales. I mean do you have a sense of what that split is right now.

Baird Whitehead

John, do you have that number handy?

Steve Hartman

Yes, under our preliminary drilling budget for 2013, we are currently planning on drilling 22 wells in Gonzales and 18 in Lavaca.

Scott Hanold - RBC Capital Markets

Okay, thanks for that and one more question if I could, you talked about de-risking a lot of your Lavaca acreage and you feel good about the majority of the stuff here in Gonzales to get you 285 locations. Does that location count include a de-risk of Lavaca and can you kind of give us some color on where that 285 could go as you see better down spacing and test some more of your acreage.

Baird Whitehead

John, can you answer that question?

Steve Hartman

Yes, the 285 does not include a fully developed Lavaca County in an aggressive sense of the word. So there is more room to grow that location count with continued success in drilling the initial earning wells for the remaining units. So yes, there is some room to expand that location count.

Like Baird mentioned, the location count is not an area of medically derived number, its spots on the map. So there is some additional places we can grow that, both on de-risking and through the ability to pick up small tacks of acreages. We view it on a continuous basis, which actually ends up growing our unit count.

Scott Hanold - RBC Capital Markets

So, if you are to play the fun acreage math game or at least take your best estimate of where the 285 could with, better success over the next year, I mean could it get upwards of 400 locations, am I in the ballpark?

Steve Hartman

I think that might be a little more aggressive than we’d be willing to say right now. I think it’s going to be over 300, but under 400.

Baird Whitehead

Scott, I think just looking at Lavaca County, there’s room to down space in Lavaca County. We have not taken it into any consideration at all at this time. Just a ballpark, we can probably increase Lavaca County by itself, probably by 50 locations or so.

Scott Hanold - RBC Capital Markets

Okay, alright guys, thanks for that quarter.

Baird Whitehead

Alright, thanks Scott.

Operator

And our next question comes from Amir Arif with Stifel Nicolaus.

Baird Whitehead

Good morning, hello.

Amir Arif - Stifel Nicolaus

Sorry about that, can you hear me?

Baird Whitehead

Yes, we can hear you now.

Amir Arif - Stifel Nicolaus

Okay sorry. So just on Lavaca County, I mean the economics are great. So can you just some more color in terms of why your partner is on non-consent?

Baird Whitehead

Well, we don’t know specifically Amir. I mean at this time we are speculating that since they are a large player in the play itself and that is all operated by them, we feel they are just focused on our operating position. We have no reason to believe that the results of these wells weigh on that decision, because we don’t think they would. But we think they are just so preoccupied with the other part of the play, which they are a large player, that is just a focus satiation.

Amir Arif - Stifel Nicolaus

But this is operated by you, right, so really its them just deciding to go non-consent on the total you are basically looking to drill, is that right?

Baird Whitehead

I didn’t follow the question Amir.

Amir Arif - Stifel Nicolaus

No, I’m just wondering, I mean you are operating the AMI area, right.

Baird Whitehead

That’s correct.

Amir Arif - Stifel Nicolaus

So I mean you determine the location and for them, I mean there’s really no focus for them on an operational perspective right.

Baird Whitehead

Exactly.

Amir Arif - Stifel Nicolaus

Is there any issue or do they have a right to back in after payout of anything like that.

Baird Whitehead

Once they go non-consent on the initial unit, well they are out of any subsequent development wells. So if you are talking about a 700-acre unit, typically we could probably drill six to seven wells in each unit, so the initial wells, they would be out of the subsequent development wells within that unit.

Amir Arif - Stifel Nicolaus

Okay, and then just a separate question on the new-acreage acquisition that you are doing to replenish the inventory. Is there specific focus in terms of where you are looking?

Baird Whitehead

It would be bold on a county stuff, but we think that we can continue to add. John do you want to add any more color to that please?

Steve Hartman

Yes, if you seen our acreage map there is a lot of bolt on that Baird mentioned that we can fill in the white space between some of the acreage blocks that we currently hold. We also have an acreage position in south western Gonzales that is not immediately adjacent to the current focus of our activity and we would also like to grow that position as well, just to give us a little more diversity in the play and I think there is some other compelling geologic reasons to be down there, based on the activity of some of the offset operators.

So southwestern Gonzales around our existing acreage holdings, which we are continually growing, as well as bolt on and filling in the spaces in the northeastern Gonzales and Lavaca Country acreage that we are concentrating on would be where we would focus on.

Amir Arif - Stifel Nicolaus

So, you are not really looking to put out acreage in a new play altogether, like in the Permian or somewhere else.

Baird Whitehead

We have a stealth team and in effect right now that by definition of course it’s looking at new things to do. It could be the Permian, it could be other areas, we are trying to get far enough right in front of the curve on these plays, so as you don’t have to pay an arm and a leg for acreage. Because once you get up into the thousands of dollars per acre or tens of thousand dollars per acreage, it just doesn’t make a lot of sense to us. So if we get into to a new play, pick up the acreage that its up $500 an acre, it just makes a lot more sense and that is where our stealth team is focused on right now.

Amir Arif - Stifel Nicolaus

And then just one final question, just if you can give some color on the Viola results, was there something specific with the well, which is why you would look to drill another well or just some color in terms of the prospects of that play.

Baird Whitehead

Well, at this time it appears that the interval that we focused on, it could have leaked out to a higher or different interval. That’s why we are thinking this new interval that we may test in the vertical well would now be the new play. It doesn’t appear we have a lot of pressure in this well, and for that reason we are just not making a lot of oil. So it appears to be a pressure problem more than anything, but sort of good news, bad news. If the new trap is a stratographic trap associated where there’s up-hold interval, it may become the new play type.

Amir Arif - Stifel Nicolaus

Thanks guys.

Baird Whitehead

You’re welcome.

Operator

(Operator Instructions). And we will hear next from Welles Fitzpatrick with Johnson Rice.

Welles Fitzpatrick - Johnson Rice

Good morning.

Baird Whitehead

Hey Welles.

Welles Fitzpatrick - Johnson Rice

In Lavaca, I just want to make sure I’m doing this math right. With the 300 locations you talked about, is that implying around 60 acres spacing.

Baird Whitehead

No, we actually right, I think we’ve got our acreage count based on 152 acres per location to be exact.

Welles Fitzpatrick - Johnson Rice

I’m sorry. If you were to do kind of the straight, I know you factored out some acreage, but if you were to do kind of the ultimate spacing and within a unit that you knew was good, would it still be – I mean would it be down closer to 100.

Baird Whitehead

Yes, I mean that was the basis of – I think it was Scott Hanold’s question. How many locations we could possibly add in Lavaca Country, that’s where the 50 additional wells came from, that would be on a shallower spacing, yes.

Welles Fitzpatrick - Johnson Rice

Okay, perfect and then as far as leasing down there is concern, are you guys still seeing that kind of 2,000 to 3,000 an acre on the ground or has that started to move up with your successes.

Baird Whitehead

It’s moved up somewhat. We may want to continue to pick up acreage for 4,000 plus of those and as Steve pointed out, every time our partner goes knocking sand in Lavaca County, that essentially brings around 300 acres, because their interest has the average unit size. That brings about 300 acres in the door at no cost by them going non-consent. So I means its anywhere there from zero, then we paid up to maybe $4,000 an acre by just picking and choosing.

Welles Fitzpatrick - Johnson Rice

Okay, and with the partner going non-consent, I assume that you guys might drill some cotton valley in ’13, which I know its never formalized or kind of battered around. Is that on a back runner?

Baird Whitehead

Yes, I can almost in fact say we will not drill any Cotton Valley wells in 2013.

Welles Fitzpatrick - Johnson Rice

Okay perfect, that’s all I have. Thanks so much.

Baird Whitehead

Just to say one other thing, we get the question, well what kind of gas price would you resurrect, like gas drilling. The way we look at life and we’re trying to get to a self-funding satiation, there is almost I would say no gas price, but even at $4, $4.50 or $5 gas price, the economics just don’t compete with what we’re doing in the Eagle Ford. I think at the end of day, maybe some of these gassier assets being trade bate or you sell them to put money to better use. But I can say that under almost no scenario, any scenario would we resurrect any gas drilling, including the Cotton Valley. Sorry.

Operator

And moving on, we do have a question from Adam Leight with RBC Capital Markets.

Adam Leight - RBC Capital Markets

Hi, good morning.

Baird Whitehead

Good morning.

Adam Leight - RBC Capital Markets

Just a couple more. First off on the Eagle Ford acreage, I presume the filling is just as you don’t have substantial holdings within the area of the sellers, it is (inaudible).

Baird Whitehead

Ask that question one more time, I’m sorry.

Adam Leight - RBC Capital Markets

The sellers of the acreage that you are picking up in the Eagle Ford is presumably just holders who don’t have been up in those position to make sense that you can bring it in at a usably cost.

Baird Whitehead

Okay, yes, in some cases its just stranded acreage for other folks that it doesn’t make sense for them to keep and in some cases in brand new acreage that we are leasing off the royalty in there, so it’s a mix of both.

Adam Leight - RBC Capital Markets

Okay and then in the Granite Wash, are you still rejecting ethane and is that in your guidance. If so, how much?

Baird Whitehead

We are currently not rejecting ethane today. Our guidance assumes that we will not reject ethane if I’m not mistaken Steve, correct.

Steven Hartman

That’s true, but how we accounted for in the lower NGO prices is we lower our assumption for NGO prices to 35% of WTI, which historically we’ve been at 45%. So we are not assuming ethane rejection, but we are assuming overall lower NGO prices.

Adam Leight - RBC Capital Markets

That makes sense. And then just overall gas decline rate, if you are not drilling, what are we looking for in ’13 and beyond.

Steven Hartman

It’s about 25%, almost 25%. That’s the instantaneous rate. That rate decreases as times go up, but the instantaneous rate, our base decline excusing the Eagle Ford is about 25%.

Adam Leight - RBC Capital Markets

Okay and then, I guess its kind of an obvious answer, but finding of any outspend a couple years out, presumably that debt available, not much left in the portfolio itself, but I guess there is some possibility. Is that kind of your thinking?

Baird Whitehead

Well, I’ll let Steve answer that question, but as far as we do have gassy, we have Mississippi which is a nice position that we give people knocking on our door. Of course if we still have the Granite Wash it would be a good asset, and we have east Texas.

Even though at this point in time we’ve elected not to try to market any of those, just because we think of maintaining some kind of mix between gas and oil is important for the same reason we don’t want to be 90% gas, we don’t want to be 90% oil, but I mean we still have some good gas assets. It would attract a nice value, especially gas prices increases somewhat. Steve, as far as the debt.

Steve Hartman

Well, we obviously haven’t gone out as far as 2014 or 2015 as far as outspends, but we do feel comfortable in saying that they are going to go down, just like they went down from ‘13 over ’12.

And our leverage position where it’s at, we think that we could easily absorb that in the debt markets. In 2013 we can refinance our 10 3/8 senior notes, so that could be a good time to may be tack on a little bit more and to start addressing 2014, but I guess that the short answer is, our leverage and our debt capacity is very healthy, so we should be able to absorb any outspends in that market.

Adam Leight - RBC Capital Markets

Kind of you anticipated my question on the (inaudible) and lastly on that concept, do you have any indication from Moody’s that they are going to get more rational?

Baird Whitehead

I don’t know. I guess I can’t really comment on what they are thinking right now. I’ve been working with them, I’ve provided them with numbers and so I guess we will see over the next week or so what they’ll decide to do.

Adam Leight - RBC Capital Markets

Great. Thanks very much.

Baird Whitehead

Thank you.

Operator

And our final question comes from (inaudible) with Jefferies & Company.

Unidentified Participant

Good morning. Just a quick question on your Granite Wash acreage. Have you evaluated the shallower intervals in that acreage?

Baird Whitehead

We have spent some time on it. We don’t really think we have anything perspective to shallower now. As you go north on our acreage position, you sort of run into the Cleveland play, but at this point in time, our acreage is a Granite Wash play, Granite Wash b2b specific.

Unidentified Participant

Thank you.

Baird Whitehead

Thank you.

Operator

And with no further questions in the queue, I would now like to turn the call back over to you Mr. Whitehead for any additional or closing remarks.

Baird Whitehead

Well, thank you for joining the call. Again, I’ll continue to say I think this company is making progress and I hope you can see it and we welcome the fourth quarter and going into 2013 to continue to communicate how well we think we are doing. Thank you very much.

Operator

And again, that does conclude this call. We do thank everyone for participating today.

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