Ranger Oil Corp (ROCC) 2012 Q3 法說會逐字稿

Good day, everyone, and welcome to the Sinclair Broadcast Group third quarter 2012 earnings conference call. Today's conference is being recorded. At this time I'd like to turn the conference over to President and CEO, Mr. Baird Whitehead. Please go ahead, Sir.

Thank you very much, Jenny.

Good morning and welcome to Penn Virginia's third quarter conference call. I'm 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 section of the press release as issued last night, as well as the 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 close yesterday.

The third quarter 2012 continued a trend of solid financial results, achieving our fifth consecutive quarter of $60 million of EBITDAX or greater with year-over-year increases in oil and natural gas liquid revenues and gross operating margins. We also continue to drill what we consider are 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 number of recent developments which we think are significant for Penn Virginia's primary goals of continuing to grow our oil inventory and simultaneously strengthening our balance sheet and liquidity. First of all, since our second quarter in which we announced the closing of $100 million sale 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 $70 million higher than the previous credit facility, along with more favorable covenants and similar pricing.

Secondly, we raised $155 million of net proceeds through the issuance of 9.2 million shares of common stock and $115 million of 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 counties and recently increased our net acreage 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 or six plus year inventory for a 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 costs quarter over quarter of about $3.1 million. This reduction in lease operating costs 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 received a one-time settlement to unwind an 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 focused on lowering our operating costs.

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 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 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 of 2012.

So, to 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 the 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 a premium oil pricing we are receiving since we sell into the LLS market as well as continued emphasis on lowering our operating costs, 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 growing acreage position in Gonzales and Lavaca counties puts us in a position to demonstrate ongoing oil growth.

Fifty-nine 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. Result of the recent wells drilled and completed were detailed in our press release.

Post processing, our gross Eagle Ford production for the quarter was about 6300 net barrels of oil equivalents per day which, over the quarter, averaged about 84% oil, 9% natural gas liquids, and 7% residue gas. We expect Eagle Ford production to decline slightly in the fourth quarter due to reduced rig count in the second and third quarters, but also expect to resume growth later this year in 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 reserve internal type curve with Gonzales County based on the average peak rate of 986 barrels of oil equivalent per day for the applicable 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 stages. For the 49 full length wells we have drilled and completed, we've averaged lateral lengths of about 3900 feet and 16 frac stages.

Results in Lavaca County and our farm out acreage continued 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 pressures, and average 30-day rates for the applicable five walls of 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 hold, but at the same time the 30-day rates are a little more.

While the initial potential results are meeting expectations, the percent of the Lavaca County acreage that will be productive is exceeding our original expectations. We just completed the furthest [dine-dipped] well named the [Lial] well, and it's 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 head by the way, with a 3900 pound flowing pressure and it is very, very early in its cleanup process. So, that in itself tells us we have a good well here.

With results like this and the fact that we have 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 reasonably about half of the acreage.

Steve in a minute will give you some guidance information with preliminary CapEx for 2013. This guidance assumes that our 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 of next year. If they continue to go non consent 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 will continue to make operational -- 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 and 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 acid and proppant, but also now the quar. The guar itself, by self-sourcing has saved us about $300,000 to $400,000 per well. We also are now in general drilling 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 increase in frac stages, but ultimately we think will increase our reserves on a per well basis and, therefore, our overall economics.

And recently we added a Pioneer rig, which has accelerated our drilling inventory into play. Just recently, on the last well, the Pioneer drill truss, we drilled that well in Gonzales County with a measured depth of almost 14,500 feet and a lateral length of about 4800 feet in just a little over 11 days. This is a new record for us. This is about a week less than what we'd typically expect to drill a well of this depth and lateral length in Gonzales County. Clearly, this rig has taken us to a 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 waste to drill, and higher strength proppants. But we also think that wells in Lavaca County will ultimately have higher 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 this three-rig program.

As pointed out in a release, our acreage position in the Eagle Ford is now approximately 40,000 gross, 30,000 net acres. With [die] 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. A stated goal of ours is to -- is at a minimum maintain 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. 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 location 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 we can do that going into 2015 with the annual [I] spends decreasing up until then.

Number two, we think that the current inventory of 285 locations will increase on our existing acreage as we de-risk more of our Lavaca County acreage and include more die 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 a 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 the 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-operated basis in the granite wash. Also, as we discussed in the release, we have some operational issues with our Viola Lime test well. We were only able to simulate about 1100 feet of a planned 4100 foot lateral. We decided to go ahead and complete the well as is because we thought that it would give us the answer we were looking for. It only tested 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 hole in the vertical well, in which we had good mud log shows in the existing well. This up hole interval can ultimately be a new horizontal target depending on the completion 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.

Thanks, Baird, and good morning.

I'll start with a 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 the 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. On an equivalence basis, we realized $8.37 per Mcfe in product revenue this quarter which was 22% higher than the prior year quarter. Hedges added $8.08 per barrel to our realized oil price and $1.05 per Mcfe to our natural gas price. As a side note, our reported product revenue does not include cash hedge settlements 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 improvement 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 costs, lower compression charges, and lower water disposal costs. 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 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 loss for adjusted EPS. Adjusted net loss excludes non-cash charges and derivatives, impairments, restructuring costs, and other one-time costs. 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 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 our liquidity and pre fund the 2013 drilling program. In the last few months we've raised $155 million net in the common and convertible preferred equity offerings. We closed on the Appalachian basin sale raising about $100 million and we 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. All together, we've 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 on 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. 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 when at that point steps down to 4.25 for the first half of 2013, and 4 times thereafter. We also extended the maturity of the credit facility to 2017. This refinancing serves 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, it's 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 costless collar with $3.50 floors and $4.30 caps, 5 million a day were hedged using a swap at $4.04. We did not add any oil hedges this quarter, but we're well hedged at this point, so we can afford to be patient with pricing. For the balance of 2012, we have 68% of our oil hedged as a percentage of the midpoint of guidance with weighted average floors and caps of $100.80 by $102.55.

Our natural gas hedge position for that same time period has us 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 $100 a barrel weight averaged and our natural gas is hedged by recent trades I just mentioned. Our hedge has 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 to guidance for 2012. Total production guidance is now 38.4 Bcfe to 38.9 Bcfe which is a slight increase to the midpoint of our previous guidance. This implies production for the fourth quarter of 7.9 Bcfe to 8.3 Bcfe. We're being a little conservative with our fourth-quarter production because the timing of well completions which are more heavily weighted towards the second half of the quarter.

We're increasing our oil guidance to 2.22 to 2.25 million barrels. This implies fourth quarter oil production of 527,000 to 557,000 barrels. This is lower production than the third quarter, as Baird explained earlier, but it is 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're now forecasting $284 million to $303 million. This is an $11 million increase from the midpoint of our previous guidance. The increase is 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 toward a slight improvement of $0.02 per Mcfe building on the improvements we've already discussed. Same with G&A. We expect continuing improvement, so we're lowering the midpoint of our guidance by $0.05 per Mcfe for recurring cash G&A.

Restructuring charges are mostly complete, so our guidance for that expense is now $1.2 million lower than our previous guidance. We're raising the midpoint 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 NGLs, $3.51 for natural gas, and a plus $14 differential between the WPI and LOS markets, which would yield us about a $6 realized price over WTI net of transportation.

We are raising 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 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 is $14 million of additional capital in 2012 to pick up their working interest. Now, keep in mind that this is a good outcome for us. These are excellent 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 to 37 Bcfe as compared to 34 Bcfe for 2012 pro forma for the Appalachian basin sale. We expect 2013 oil production will be approximately 2.7 million to 2.8 million barrels or about a 25% increase over the midpoint of 2012 oil production. We expect oil and NGL production together will be 55% to 65% of total production.

We will continue to operate a three-rig program in Eagle Ford and concentrate nearly 100% of our investment in oil and NGL rich plays primarily within the existing Eagle Ford acreage. Our anticipated capital program is $310 million to $345 million. We expect our cash out spend for 2013 will be around $125 million to $150 million with this type of a program. Again, this plan assumes our partner will participate in the 2013 Lavaca County program. If our partner goes non-consent for all of 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 mentioned, we'd expect that we would get a partner. We should know the full extent of their participation by second quarter 2013.

As I mentioned earlier, the 2013 program is fully funded at this point. To put this in context, we ended 2011 with around $100 million outstanding on our credit facility. If you assume the midpoint of the outspend guidance I just provided, we end 2013 with just slightly above $100 million outstanding on the credit facility. So, the capital we've raised over the last few months together with increasing cash flows from operations, that's funding better without adding any additional debt to the balance sheet.

Baird, that concludes guidance review.

Thanks, Steve.

Just to wrap things up, I hope that you're seeing that this Company's making progress. Even though it's been painful, we've made a lot of progress in this third quarter. We strengthened our balance sheet and we, therefore, improved our financial liquidity. We've taken that risk off the table, which we thought was important to do going into 2013. And we think we're now well positioned to fund our future growth. This, along with fiscal discipline going forward, will allow us to grow to a position that we think that we can self-fund our capital program by 2015. And I can tell you that we are committed to making this goal.

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

Thank you, Sir.

(Operator Instructions)

We will go first to Neal Dingmann with SunTrust.

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

Well, talking about Lavaca County specifically, with this Leal well, which is the furthest down-dip well 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 County 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 oilier part of the window. A couple wells we have drilled there have lesser IPs, but the one thing that we have also found out, that they have much lesser [declines] associated with them. 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 ultimately 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.

Okay. And 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 have, and just thoughts on that or going forward with your activity on -- going after Pearsall?

Well, we've intentionally not talked about the Pearsall because, just because. We did drill a pilot hole two or three months ago, gathered some science information, took some side wall cores. Based on it, we do plan on spudding a Pearsall horizontal well later this year, probably the results will not be known until the beginning of next year. But it is our plan to test the Pearsall on our acreage. We do think that, probably out of the 30,000 acres 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, there's not -- having said all that, there's not a lot of data up our way because the play has primarily been in the southwest part of the trend. EOG has drilled some wells, that play has come toward us, but we'll know a lot more about the play first quarter next year.

All right. Great color. Thanks, Baird.

All right. Thanks.

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

Good morning. When -- looking into next year you obviously talked about if your partner up in sort of the Lavaca County area does not participate, you'd be looking to find a partner. 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 another way to do that is just take a higher working interest, which I think would tend to be sometimes a better capital return position.

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're expensive. You've 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 one of these things, with a 96% interest -- if our partner goes non-consent, it's just very difficult for us to take on that additional risk.

We think that it would 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 would be attractive. And at the end of the day, with some kind of 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, at this point in time, it's just -- we can't speak out of both sides of our mouth and say we're going to spend a lot more money and drill these wells. At the end of the day, it's the operational risk that gives us some pause.

Okay. Okay. So, diversification is a key part of that.

Exactly. That's exactly right.

And, as you look in to 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? Do you have a sense on what that split is right now?

John, do have that number handy?

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

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 you have in Gonzales to get you 285 locations. Does that include -- does that location count include a de-risked 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?

John, can you answer that question?

Yes. The 285 does not include a fully developed Lavaca County in the aggressive sense of the word. So, there's more room to grow that location count with the continued success in drilling the initial earning wells for the remaining units. So, yes, there's some room to expand that location count. Like Baird mentioned, the location count is not a arithmetically derived number, it's spots on a map. So, there's some additional places we can grow that, both on de-risking and through the ability to pick up small tracks of acreage, as we do on a continuous basis, which actually ends up growing our unit count.

So, if you were to play the front acreage math game, or at least take your best estimate of where that 285 could go with better success over the next year, are we talking -- could it get upwards of 400 locations? Am I in the ballpark?

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

Scott, I think just looking at Lavaca County, there's probably room -- there's room to [die] space in Lavaca County and we've not taken it into consideration at all at this time. Just a ballpark, we could probably increase Lavaca County by itself, probably by 50 locations or so.

Okay. Very good. Thanks for that. Good quarter.

All right, thanks, Scott.

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

On Lavaca County, the economics are great, so could you just give some more color in terms of why your partner is going non-consent?

Well, we don't know specifically, Amir. At this time, we're 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 their operator 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're just so preoccupied with the other part of the play, which they are a large player that it's just a focus situation.

Okay, but this is operated by you. Right? So, really it's them just deciding to go non-consent on the [wells] you're basically looking to drill? Is that right?

I didn't follow the question, Amir.

I'm just wondering, I mean, you are operating the AMI area, right?

That's correct.

So, you determine the location, and, for them, it's -- I mean, there's really no focus for them on an operational perspective, right?

Exactly.

Is there any issue or is there -- do they have a right to back in after payout or anything like that?

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

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

It would be bolt-on kind of stuff that we think we could continue to add. But, John, do you want to add any more color to that, please?

Yes. We've got a -- if you've seen our acreage map, there's 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 southwestern Gonzales that is not immediately adjacent to our -- the current focus of our activity, and we'd also like to grow that position as well just to give us a little more diversity in the play. And I think there's 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 County acreage that we're concentrating on would be where we would focus on.

So, you're not really looking to try that acreage in a new play altogether, like in the Permian or somewhere else?

We have a stealth team in effect right now that, by definition, of course, is looking at new things to do. It could be the Permian, it could be other areas. We're trying to get far enough out in front of the curve on these plays so 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 thousands of dollars per acre, it just doesn't make a lot of sense to us. So, if we get into a new play, pick up acreage that is sub $500 an acre, it just makes a lot more sense and that is what our stealth team is focused on right now.

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

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're 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're 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 stratigraphic trap associated with this up-hole interval, it may become the new play type.

Thanks, guys.

You're welcome.

(Operator Instructions)

And we will hear next from Welles Fitzpatrick with Johnson Rice.

Good morning. 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-acre spacing?

No, we actually -- right now I think we've got our acreage cap based on 152 acres per location to be exact.

But, 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 the ultimate spacing within a unit that you knew was good, would it still be -- would it be down closer to 100?

Yes. That was the basis of, I think it was Scott Hanold's question, how many locations we could possibly have at Lavaca County. That's where the 50 additional wells came from. That would be on a shallower spacing, yes.

Okay. Perfect. And then, as far as leasing down there is concerned, 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 success?

It's moved up somewhat that we -- to be able to continue to pick up acreage for $4,000 or less. And, as Steve pointed out, every time our partner goes non-consent in Lavaca County, that essentially brings around 300 acres, because their entry is times the average unit size, that brings about 300 acres in the door at no cost by them going non-consent. So, it's anywhere then from zero and we paid up to maybe $4,000 an acre by just picking and choosing.

Okay. And, with the partner going non-consent, I assume that the idea that you guys might drill some Cotton Valley in '13, which I know was never formalized, but kind of batted around -- is that on the back burner?

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

Okay. Perfect. That's all I have. Thanks so much.

Just to say one other thing. We get the question, well, what kind of gas price would you resurrect gas drilling? The way we look at life and with trying to get to a self-funding situation, there's almost, I don't want to say no gas price, but even a $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 the day, maybe some of these gassier assets become trade bait 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.

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

Just a couple more. First off, on the Eagle Ford acreage, I presume the fill-in is just guys who don't have substantial holdings within the area that are sellers? Is that kind of the concept?

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

The sellers of the acreage that you're picking up in the Eagle Ford, is that presumably just holders who don't have enough of a position to make sense that you can bring it in at a reasonable cost?

Okay. Yes, in some cases. Some cases it's just stranded acreage for other folks that it doesn't make sense for them to keep. In some cases, it's brand new acreage that we're leasing off the royalty in there. So, it's a mix of both.

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

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

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

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

It's about 25%, almost 25%. That's the instantaneous rate. That rate decreases as time goes out, but the instantaneous rate -- our base decline, excluding the Eagle Ford, is about 25%.

Okay. And then, I guess -- it's kind of an obvious answer, but funding of any outspend a couple years out, presumably you have debt available, not much left in the portfolio to sell, but I guess there's some possibility? Is that kind of your thinking?

Well, I'll let Steve answer that question. But, as far as -- we do have gas, we have Mississippi, which is a nice position that we get people knocking on our door. Of course we still have the Granite Wash that would be a good asset, and we have East Texas. At this point in time, we've elected not to try to market any of those just because we think maintaining some kind of mix between gas and oil is important. And the same reason we don't want to be 90% gas, we don't want to be 90% oil. We still have some good gas assets that would attract a nice value, especially if gas prices increase somewhat. Steve, as far as the debt --

Well, we obviously haven't gone out as far as 2014 or '15 as far as outspends, but we do feel comfortable 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. We have our -- in 2013 we can refinance our 10.375 senior notes, so that could be a good time to maybe tack on a little bit more and start addressing 2014. I guess 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.

Okay. You anticipated my question on the 10.375. And then, lastly on that debt concept, do you have any indication from Moody's that they're going to get more rational?

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

Great, thanks very much.

Thank you.

And our final question comes from [Iktat Fung] with Jefferies & Company.

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

We have spent some time on it. We don't really think we have anything perspective 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 B to be specific.

Thank you.

Thank you.

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.

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.

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