Ranger Oil Corp (ROCC) 2011 Q1 法說會逐字稿

Good day, and welcome to the Penn Virginia Corporation first-quarter 2011 earnings conference call. Today's conference is being recorded.

At this time, I would like to turn the conference over to Baird Whitehead, President and CEO. Please go ahead, sir.

Thank you, Camille. Good morning, and welcome to Penn Virginia's first-quarter 2011 conference call. I am joined today by various members of our team, including Nancy Snyder, our Chief Administrative Officer; Steve Hartman, our CFO; and Jim Dean, our Vice President of Corporate Development.

Prior to getting started, we would like to remind you the language in our forward-looking statements section of the press release as issued last night, and the form 10-Q that will be filed, which will apply to our comments today. We have several items to cover. We will expand a bit on the earnings and the operational update releases that were issued last night, briefly covering our first-quarter results, strategy, current exploration, and production operations, and further plans for 2011.

Prior to jumping into these matters, I'd like to take a moment -- Jim Dearlove, who retired yesterday, thank him for his 30-plus years of service to Penn Virginia Corporation, including 15 years as our President and Chief Executive Officer. We all wish Jim good luck in the future, and we thank him for his leadership in growing this Company.

Our first-quarter production was 12.2 Bcf equivalent or 135.2 million a day, which is a 21% increase over what it was in the first quarter of 2010, including -- or taking out the sales associated with our Gulf Coast assets that we made in January of last year. The decline in production from fourth-quarter 2010 of 13.1 Bcfe or 142.5 million a day was not unexpected, given our transition from drilling primarily in our natural gas plays and moving that focus on drilling to our new Eagle Ford shale position.

In the first quarter, 20% of our production was from oil and natural gas liquids, up from 17% in the first quarter of last year. We expect production to be flat in the second quarter of 2011, but then we plan on increasing that production as the second half of the year progresses, with an increase in proportion of that production coming from crude oil and natural gas liquids. And most of that liquids growth will be, of course, from our Eagle Ford shale, which we expect to be approximately 15% of our total production in the fourth quarter of this year as compared to being very small in the first quarter.

In the first quarter, we had an operating loss of $28.5 million, which is primarily attributable to increases compared to the first quarter last year and exploration expense and DD&A expense, as well as a 24% decrease in our realized natural gas price. Direct operating expenses improved to $2.54 per Mcfe from $2.73 per Mcfe in the first quarter of last year.

In our adjusted EBITDAX, a new metric that we will start reporting on routinely in the future, was $44.1 million in the first quarter compared to $49.1 million in the first quarter of 2010. Our net operating loss on a diluted share was $0.58, and if you adjust for non-cash charges or changes in the fair value of derivatives or structuring gains and losses, sale of assets and other items which may affect in comparability of prior quarters, our net loss per share was $0.51. During the first quarter, we experienced $16.4 million of dry hole cost, along with $10.6 million of unproved property amortization, which of course, contributed significantly to our quarterly loss.

Prior to commenting on our operational activities I wanted to touch briefly on our current strategy. We continue to de-emphasize any investment in natural gas drilling other than what we have initiated in testing our Marcellus position in north central Pennsylvania. Instead, our emphasis is on investments in those drilling opportunities in which oil and natural gas liquids are the primary phase.

In fact, natural gas liquid production is expected to go from 18% of our production in 2010 to 29% of our production in 2011. By the fourth quarter of this year, we expect it to be approximately 35%. So, you can see that it is growing. It is growing considerably, which also bodes well for our growth extending over into 2012.

Of course, an integral part of that strategy is our position in the Eagle Ford shale. Since August, we have increased our position in what we consider a geological attractive portion of the volatile oil window from about 7,000 net acres to our current almost 13,000 net acres at a cost of a little over $4,000 per acre. I can tell you we're continuing to focus on building that position. We have an internal goal of building it to 25,000 net acres by the end of the year.

In addition, we will continue to high grade our asset base with a consideration to monetize our lower margin natural gas assets such as our Arkoma and Appalachia CBM properties, and also include monetizing a portion of our Marcellus assets. Taking that money and redeploying it into oil and liquid projects such as the Eagle Ford shale, maybe even including resurrecting our cores on our cotton valley program toward the end of the year.

Operationally, other than the results of our development in the Granite Wash wells completed that were outlined in our press release, we're just not ready to report at this time on the results of our 2 Marcellus and 2 Eagle Ford wells that we recently completed. But I can tell you, as soon as we have concrete completion results on those 4 wells, we will issue a separate press release for both Marcellus and Eagle Ford shale.

We drilled 12 wells during the first quarter, included are 6 successful Granite Wash wells in the Mid-Continent, 2 successful Eagle Ford shale wells that we just completed, 2 Marcellus wells which we also have just completed. And 2 unsuccessful wells in the Mid-Continent, one of which was a Granite Wash well that we had drilled in [class G] prospect area, and one of which was a horizontal top well in Custer County, Oklahoma. In addition to these 2 wells expense, was a third well that we actually drilled at the end of 2010 that was under evaluation at that time, that subsequently we deemed to be unsuccessful this quarter.

In the Eagle Ford shale, we currently have 3 rigs drilling. The third rig recently moved from the Mid-Con after we drilled our final Granite Wash well for 2011, and right now we're drilling our third -- excuse me, our fifth through seventh wells, while having just completed our second and third wells, and having our fourth well waiting on completion.

Our initial well that we reported on in the first quarter in January phone call for year-end 2010 results, continues to flow, and it is not on our official list at this time, but continues to flow almost 500 barrels a day, and almost 250 Mcf a day. And that's after being online for about 80 days. And to date, it's made almost 50,000 barrels and about 45 million cubic feet of gas, even though that gas estimate flared. We initially modeled these wells at 280,000 barrels equivalent, but based on this 1 well of ores, along with what's happened close to us by the rest of the industry, we now think ultimately the reserves of these wells will exceed our original estimate.

In addition, we expect to have our transportation and processing facilities in place by early June, which will allow us an additional 190 barrels per million of natural gas liquid recovery, which will only improve the well economics. Ultimately, the flow stream will consist of 75% wellhead oil, 15% NGLs, and 10% residue gas. We are already starting to build drilling efficiencies into this play. The first couple of wells, because of the science involved, took about 30 days to drill. We now think with a revised casing program and directional program, we think we can spud to TD these wells in about 15 to 20 days at a drilling and completion cost of about $7 million, which with a typical well would be about a 4,500-foot lateral and 15 frac stages.

These lower drilling costs, along with the improved EURs, of course, is only going to improve the economics of the play. We have a good drilling contractor in place. We have a long-term frac agreement in place, which will allow us to ramp this program up as the year goes on.

Right now we have 29 wells in this current plan, but that was based on a 30-day well. If we continue to beat that 30-day number and stay in this 20-day number, there's a possibility that program could ramp up toward the end of the year even further. To remind everyone, we have between 90 and 115 drilling locations in the Eagle Ford alone. We also think we have some upside especially in the Austin Chalk. And with these 3 drilling rigs, the goal is to increase our acreage position, of course, this is now a very important play to Penn Virginia and its growth in liquid production.

Now switching gears to the Marcellus shale, there's not a lot to talk about at this time, we have completed our first 2 wells, we will start completing our third well any day, and we are drilling the fourth well as we speak. We don't have anything to report on the first 2 wells, and once we have some concrete results in hand, as I said earlier, we'll make a supplemental operations release.

Right now our plan includes drilling 11 wells versus the 14 wells originally planned, that primarily is just because we're not going to get 14 wells drilled this year because of timing issues. To remind everyone, we are currently focused on our 35,000 net acre position in Potter and Tioga County, Pennsylvania.

In the Mid-Con, as I said earlier, we finished up on our last operated development, a Granitite Wash well for 2011, and that rig was subsequently moved to the Eagle Ford. The remainder of our development program for this year will be as a non-operator with Chesapeake in our South Clinton field.

Of the 8 gross and 4.1 net wells that we drilled in the first quarter in the Mid-Con, 6 gross and 2.4 net development wells, Granite Wash development wells, were successful. 2 gross and 1.6 net exploratory wells, as well as 1 gross and 0.5 net well that we had drilled late last year, were determined to be unsuccessful. Thus far in 2011 we have completed 8 gross and 3.8 net wells in our South Clinton field, with IP rates of anywhere from 1.6 million a day to 10.2 million a day, which is an average of 6.7 million a day.

We have discussed in previous conference calls the interference issue that we are seeing between wells that we have taken into account going forward, and these wells are still very attractive economically, still at the same time having an inventory of about 80 drilling locations within our AMI with Chesapeake. We now model a typical Granite Wash well within EUR of 5.3 Bcfe equivalent post-processing, which has an IP of 7.3 million a day also post-processing. So the 6.7 million a day average reported for our completion program in the first quarter is about 8 million a day post-processing. So you can see that we are well within our expectations for the new type curve that we're modeling, which still has very attractive rate of return.

As I just discussed, our exploratory efforts in the Granite Wash and other horizontal oily plays that we have, continue to drill in the Mid-Con. Admittedly, we've been disappointed to date. We have had very little success. Going forward, we still have to exceed up even though we have put that exploratory program on hold for the remainder of 2011. Our plan is, for the remainder of this year is to acquire some additional seismic over a carbonate prospect that we have and in some other areas.

We have previously discussed our class g compile results, the more recent well that we had determined to be dry was our Tonkawa well in Custer County, Oklahoma. That well, based on a pilot hole that we had drilled, we thought was going to work. It had some more than adequate porosity and permeability based on some leak-off tests. But after the fact, the well tested almost fresh water, which we had yet to determine the source of that fresh water. At 9,000 feet deep, it's almost impossible to explain where this water came from.

So, in any case, we're trying to get our arms around this. We have some other prospects in this overall Southwest Thomas area, some of the Tonkawa prospects. It certainly has not killed those. We also have some deeper Cleveland sand ideas, and we actually had seen that Cleveland sand in this first pilot hole. It appeared to have potential, but the top well we felt had better opportunity, so we focused on it. But in any case, we have some things to do there.

In the second quarter, which we did not release in our press release, we just drilled a vertical well in [Robs] County, Texas. This is an area in which we have picked up about 12,000 net acres. It was the Granite Wash prospect, the risk of it, that was a stratigraphic risk. After the fact, the Granite Wash was tight, so the risk raised its ugly head. But having said that, there's some additional things to do on this acreage. This acreage is fairly close to a St. Louis play that's currently going on.

There's also some morrow opportunities which we have to get our arm around. At the end of the day, what we're going to have to do is probably shoot at least some 2D seismic, and maybe even a 3D. But we think there's some other opportunities on this 12,000 net acres to pursue over time. By the way, we will expense this well in the second quarter, as I said, with an additional dry hole expense of about $2 million.

In the operational update, we did not touch upon our Cotton Valley update. We continue to be extremely pleased with the results to date, the wells we drilled in 2010 exceed the type curve that we had put in place. There's a very good reason that in the latter half of the year, we may decide to resurrect this Cotton Valley program because the economics are very accessible with today's gas prices and of course, oil prices. In all probability, we will take some of the proceeds from any asset monetization to reinvest in the drilling of these Cotton Valley wells.

So, with that, I'd like to turn it over to Steve Hartman have him give you an update of our financial progress for the quarter.

Thanks, Baird. Good morning, everyone. I'll be generally following the financial results section of the release on page 2 and the statement of income on page 6. This review will be comparing our first-quarter 2011 financial results with our prior-year quarter results from the first quarter of 2010.

Our first-quarter revenue was $68 million, including $26 million from oil and NGL sales, and as a percentage of total revenue, our oil and NGL revenue was about 38% of total revenue, up from 28% in the prior-year quarter. Realized prices were $4.23 per Mcf for natural gas, a 24% decline from first quarter of 2010 prices, and a major driver for our lower financial results in the quarter.

Our hedges added $0.72 per Mcf to the realized gas price for an adjusted realized gas price of $4.95 per Mcf. This compares to a realized gas price, including our hedges, of $6.64 an Mcf in the first quarter of 2010. Realized crude oil price for the quarter was $87.17 after hedges.

As Baird mentioned earlier, direct operating expenses were higher in the first quarter at $30.9 million, mainly due to higher production levels. On a per Mcf basis, however, we saw an improvement, our direct operating expenses were $2.54 per Mcfe versus $2.73 per Mcfe in the prior-year quarter, or a 7% improvement in our per unit cost.

Other operating expenses, which are mostly noncash and discretionary in nature were up primarily due to increased exploration expense, as Baird mentioned. We recorded 3 dry holes in the first quarter for a charge of $16.4 million, and also our unproved property amortization expense, another sub-category of exploration expense, was higher due to the higher amortization rates for the lease hold acquisitions we made early in 2010 in the Eagle Ford and Marcellus shales. This rate will continue to be relatively high compared to what we've seen in the past until we prove up these leases through drilling and move those costs over to proved reserves.

ED&A expense was higher than the prior-year quarter, due to higher production volumes, but was in line with prior period on an Mcfe basis. We are reporting an operating loss for the quarter from continuing operations of $26.3 million, as Baird earlier mentioned, or $0.58 per share versus operating income in the first quarter of 2010 of $10.8 million. The decrease was primarily due to the lower gas price environment, higher exploration expense, higher DD&A rate, and higher direct operating expenses. It was offset by higher oil and NGL revenues.

Our adjusted net loss attributable to PVA, a non-GAAP number that is reconciled on page 8 of the release, was $23 million for the quarter. We adjust the GAAP determined net loss for noncash impacts from hedging, restructuring costs we incurred primarily in 2010, as well as gains or losses on asset sales.

While we're on reconciliation, you can see we are now reporting adjusted EBITDAX, as Baird mentioned. This is showing you the definition in our credit facility for calculating our leverage covenant with the exception that we show you in past periods, net of PVG and PVR distributions; that's really only an issue for first-quarter 2010, as we showed you in the release. For the first quarter of 2011, our adjusted EBITDAX was $44 million compared with $49 million in the first quarter of 2010. We think this is going to be a useful metric for you to gauge our core cash flow and our current liquidity.

Moving on to our capital resources and liquidity shown on page 4 of the release, cash and cash equivalents at the end of the quarter were $48 million, pro forma for the $300 million bond deal and subsequent tender offer for our existing convertible notes, all of which we completed in April. We had approximately $100 million in cash on the balance sheet pro forma. Our current cash balance is approximately $112 million, so we continue to maintain healthy liquidity levels.

A little more detail on the bond offering and tender deal I just mentioned, in April we launched an offering for $250 million of senior unsecured notes due in 2019. The deal was well received, and on strong demand, we upsided the deal to $300 million, pricing that at par with a coupon and yield of 7.25%. The primary use of proceeds was to tender for our 4.5% convertible notes due in November 2012. We received 98% of those notes back in the tender, leaving just under $5 million outstanding, which we'll redeem at maturity in November 2012. Net of the tender offer and other related deal costs, we retained approximately $52 million in cash proceeds. The rationale behind this deal is that we didn't want to let the convertible notes go current on our balance sheet, which would have occurred at the end of this year. Moreover, we wanted to take advantage of the strong bond market to refinance and add a layer of low-cost, fixed, long-term capital to our capital structure.

At March 31, we had outstanding debt of $530 million consisting of our $300 million senior notes maturing in 2016, and $230 million of convertible notes due in '12. Pro forma for the bond deal, long-term debt would have been $605 million excluding any unamortized discounts. We had no balance outstanding on our $300 million credit facility, with a $420 million borrowing base at quarter end. That's $398 million adjusted for the bond offering. We have an accordion feature on the credit facility that would give us access to the full borrowing base subject to bank participation, which I would not expect to be difficult to obtain given the strength of the bank market today, and especially our bank group. Our borrowing base is in process for a semi-annual redetermination. We expect that the borrowing base will be reaffirmed at the pro forma, not $398 million level, that was pro forma for the, or adjusted down for the bond deal.

For our total liquidity, if I assume we have access to the full $398 million borrowing base, our pro forma liquidity for the bond deal, as of the quarter end, was $498 million, subject to our leverage covenant limitation of 4 times debt that's net of our cash to adjusted EBITDAX, which we now provide to you so you can calculate any future liquidity as you see necessary. We feel our liquidity, together with cash flow from operations is adequate to fund our capitol program for 2011 and into 2012.

Moving on to hedging, just a quick comment. Our cash settlements from hedging for the quarter were $6.7 million, which gave us, as I mentioned earlier, a $0.72 per Mcf uplift in our natural gas realized price. Oil hedges were in a slight payable position this quarter. We have one trade on the books with a cap of $101.50 on the price.

Settlements on that hedge decreased our realized price of oil by $1.20 a barrel. We recently added hedges this quarter, actually since end of the quarter. We added a 500 barrel a day trade swap at $109 for the second half of this year, and 500 barrels a day for calendar 2012 using a $100 by $120 costless collar. The table on page 10 of the release summarizes our hedge position as of today, including those 2 most recent trades. And as a percentage of our midpoint of 2011 guidance, we have 57% of our natural gas production hedged, and 44% of our total commodity price exposure including oil hedged for 2011.

And moving on to our guidance on page 9 of the release, and starting with production. As Baird mentioned, we're reaffirming our guidance for total equivalent production we provided in February 23 release at 50 to 54 Bcfe. Notably, the production mix is changing. You can see we're increasing our guidance for oil production by 200 barrels per day due to the success of Eagle Ford program. We're also increasing the top end of our guidance range for the NGLs by 100 barrels per day.

We're lowering our guidance for natural gas production due to the issues in Mid-Continent, and to keep our production guidance flat. We expect oil and NGL production to be 28% to 30% of our total equivalent production for 2011. We're at 20% of production in the first quarter with initial Eagle Ford volumes coming online from the Gardner well just in late February. Now as the Eagle Ford volumes increase through the year, and we start processing the associated gas for NGLs as Baird described, we expect our oil and NGL production to increase to 35% of total equivalent production as we exit the year.

We're not changing any of our operating expense guidance numbers except for production and ad valorem taxes and exploration expense. We're increasing the production tax rate by 0.5% due to some uncertainty around the timing of refunds, but we're receiving some news that those refunds are coming earlier, so that's probably on the conservative side.

Exploration expense guidance has been expanded to include the impact of the dry hole cost, as Baird already described, and the higher lease-hold amortization rate. You'll see that we added an extra $2 million to our guidance for the dry hole cost over what we already expensed in the first quarter, and that's to allow for what we expect to expense for the Roberts County well in the second quarter.

Finally, we're raising our CapEx guidance by $20 million to $25 million, to $320 million to $370 million. This increase is found in our development drilling category, as we expect some slightly higher cost per well as we ramp up drilling in Eagle Ford and Marcellus. We also expect a little bit of an increase in lease acquisition primarily in Eagle Ford, but this will be offset by decreases in expected expenses in our exploratory program pipelines and seismic.

And Baird, that sums up our guidance.

All right. Thank you, Steve. In closing, we all understand it was a tough quarter, and we have some work to do. But we are convinced as a team that we're on the right path. We've taken the operational steps to ramp up our Eagle Ford drilling position. We have some good rigs. Have a frac crew in place. We have a goal of adding acreage to what we already have in a 3-county area in a volatile oil window. And we think we've made a lot of progress in a short period of time.

Having said that, Camille, we're ready to go ahead and take some questions.

All right. Thank you, Mr. Whitehead. (Operator Instructions) We request that you restrict yourself to 1 question and 1 follow-up question; you may requeue if you have additional questions. Neal Dingmann, SunTrust.

When you look at the 3 Eagle Ford wells, I know you haven't had results yet. Can you give us some indication on what your thoughts are on the cost as you see on -- maybe on these 3 and as you see going forward, kind of what you're planning for the remainder of the year on the well cost.

The early wells, Neal, were expensive. The reason they were is because we obtained a lot of science, we ran a lot of open hole logs, we drilled some pilot holes. We actually cored the second well. The cost of those first couple of wells were about $9.5 million to $10 million. And those first couple of wells also had a intermediate casing string of pipes set.

Going forward, we are setting our surface pipe deeper, getting rid of the intermediate string of pipe, running what they call a rotary steerable tool, and we think we can drill these things anywhere from 15 to 20 days. So the connotation that it's going to bring our drilling costs way down, and some of the recent AFEs I have seen for these Eagle Ford wells are anywhere from $6.5 million to $7 million, which would include about a 4,500-foot latter and 15 frac stages. I think we can bring our costs way down on these wells, and a couple wells, the 3 wells we are drilling right now we are on pace to be at about 15 day kind of wells. Cutting these drilling days in half is quite a feat. And being relatively new in this play.

We have a good team of folks down in our Houston office. By bringing these well costs down, and we think the reserves are going to go up on these based on our initial well and some of the offsetting results. The returns of these things are going to be very good.

And for the Mid-Con, after the results on some of the issues you had there, what is your thoughts as far as plans for further wells going after some of these deeper wells, which you're in the budget for the remainder of the year and kind of looking out.

Well, for the remainder of the year, we have no further exploratory drilling planned. We drilled, this last vertical well that we drilled in Roberts County, it deemed dry. The plan is to continue to shoot seismic, which we had planned on doing anyway for the remainder of the year, and tee this stuff back up going into 2012.

We still think we have some viable prospects to drill. This Southwest Thomas prospect in Tonkawa dry hole, we've got multiple Tonkawa prospects within that overall geographical area, and to remind everyone we have about 11,000 net acres there. We have a lot of things to do, we think. We have a deeper Cleveland Sand prospect that we need to pursue. We have [Mottenview] which was dry last year, that we think we need to drill another well in. There's a deeper springer play going on underneath this that could be some upside, that we really haven't talked a lot about at this point in time.

So in any case, we have things to do. Even though clearly we're not happy with what's happened to date, I am not disenthused. I am a very strong proponent of Mid-Con and the opportunities there. We can be very competitive in looking at these smaller geographical footprint kind of plays versus resource plays. So, as far as I am concerned, we are going to continue dying a path to be active in the Mid-Con over a period of time.

Great color. And one last one, if I could. Just on the Marcellus, you mentioned that starting to drill the fourth well. The plan is to go out a little bit longer laterals, or what's your thought on the design on the Marcellus wells going forward?

Our typical lateral length is probably going to be around 4,000 feet. The first 2 wells we drilled were a little bit shorter than that, they were our initial wells and we had some hiccups on the drilling side. But I'd say our average well is going to be around 4,000 feet. If there are lease situations that permit us to drill longer laterals, we will make an attempt to do that, assuming it's not too geologically complex. But I'd say our average lateral is going to be around 4,000 feet.

Okay. Thanks.

Amir Arif, Stifel Nicolaus.

You mentioned the possibility of some non-core assets; can you just try to quantify the amount that you were looking to raise and the timing of that?

Well, the timing would be for the remainder of this year. I'd rather not speak to what our proceed expectations would be. The monetization would also include the possible partnering in the Marcellus. To give you a range, probably around $50 million to $100 million.

And then one follow-up question. On your production guidance for next quarter, where your production will be fairly flat, how comfortable are you with that guidance? Or does it depend on just the wells that are cleaning up, what you are seeing there is comfortable enough to make you believe that you lost at any declines?

We've taken into account all the bad news. We think we're in pretty good shape. The weather issues are behind us, the odd thing to test would be the unknown, of course, as future drilling results and we continue to have wells shut in to offset new wells that we are fracking.

I really didn't mention it, I think if memory serves me correct, there was about $250 million that we had shut in, in the first quarter because of offset fracking in the Granite Wash. That's the bogey that we make an attempt to model, but still an unknown at this time. But I think in general we feel pretty comfortable with that.

Thank you.

Steve Berman, Pritchard Capital Partners.

Good morning, and congrats on being formally named CEO. Couple of questions. On your increase in acreage in the Eagle Ford, can you say if the 12,700 is all in Gonzalez or if you moved a little out of that county a little bit.

The current acreage position, the 12,700 is all in Gonzalez. We have sort of set up a tri-county, Gonzalez, Karnes, and a piece of the Ascosa County is our overall buy area. There's still opportunity to pick acreage up. We're working on deals right now as we speak. We always hear the come back -- well, you can't buy acreage. That's not true. We can buy acreage.

We feel we can pick it up at reasonable cost. We're not going to pay $10,000 an acre. We feel we can pick it up $3,000 to $4,000 to $5,000 per acre, and there's still acquisition opportunities out there that continue to come out on the market in our overall buy area.

So in general, everything we have right now is Gonzalez. We like to continue to consolidate what we have and add to what we already have in a general area. Having said that, if we can find large enough pieces in other parts of Gonzalez, Karnes and even Southeastern Ascosa, we would jump on those kind of opportunities assuming they're reasonably priced.

But the goal is to stay in that oil window in those 3 counties.

It is.

And the Marcellus, you had a formal joint venture process there; is that still ongoing, is there still a formal process in the works there?

It is. I mean, I realize people keep asking us the question. I wish I could give you an answer at this time. My only answer is we still continue to pursue it. We work on it. When something gets done, if it gets done, we will release the results of it.

Okay. And one more for me, in Roberts County, is your acreage near where Range had that very impressive initial St. Louis line well.

It's not that far away. I think as the crow flies, I think it's around 5 miles; the St. Louis is a very thick carbonate. We actually drilled down through the St. Louis in our vertical well where we were; St. Louis was tight. We feel that we could probably see the development of porosity within the St. Louis by shooting some seismic. We think as we go to the northern part of our lease hold acreage, since we had drilled in the southern part of this 12,000 acres. Which, by the way, is all contiguous, it's one solid block of acreage. It gives us a lot of running room to continue to look for new things to do.

We feel we possibly would have some opportunity in the St. Louis and the Morrow. Morrow is thick. It was very porous in our well. There's an opportunity to get up dip. Again, as you go to the north, we feel we can get up dip. We have to shoot some seismic to confirm that structural model. But those opportunities exist.

Terrific. Thanks.

Thank you, Steve.

(Operator Instructions) Eli Kantor, Jefferies and Company.

As you look out into 2012 and thereafter, at what point do you expect to become cash-flow neutral?

Steve, why don't you give that a shot.

We expect to continue to drill aggressively in 2012; that's the current plan. Right now we're not modeling that we would be cash-flow neutral in 2012, but that would be shrinking, that out-spend would be shrinking. We're thinking more about a 2013 cash-flow neutral type of a range.

What commodity price stack do you guys use in 2012-2013?

For 2012, we use a $5 natural gas price, and $90 oil. And in '13, we bump that up to $5.50 for natural gas and still keep the oil flat.

Okay. Great. Thanks, guys.

Sure.

Welles Fitzpatrick, Johnson Rice.

Good morning. You talked in the release you noted that CapEx is gone partially because of the Eagle Ford and Marcellus service costs, and then earlier you obviously talked about how you're getting those drill times down, so I assume that's almost all pressure pumping. Can you talk a little bit about how those costs are somewhat or hopefully somewhat offset by the C and J contract and the Eagle Ford, and also talk about the zipper fracks in the Marcellus and what that's doing to help out on the cost side?

Well, you're right. There will be improvements in a cost per well, talking about the Eagle Ford specifically. With 3 rigs, the C and J contract and a lot of these longer-term pumping contracts has a take or pay component to it, and the more work you do, the cheaper each frac stage becomes that you perform. Paying incrementally for chemicals and sand. So the more you drill, the more active you are, the cost per well, cost per frac stage comes down.

So in general, we're going to be extremely busy with 3 rigs possibly drilling these wells in 15 to 20 days, and that frac contract is going to help us immensely in controlling our costs.

Jump into the Marcellus and zipper frac being able to frac simultaneously or alternately from the same tab with the equipment stay in park, of course, introduces some efficiencies in reducing costs. As far as trying to quantify that efficiency right now, it's tough for me to do that until we get some more wells under our belt, but over time it will bring the cost down clearly.

One thing I want to say, jumping back to Eagle Ford, these last 2 Eagle Ford wells we completed, we actually did the same thing. It was not a zipper frac because these wells were drilled. There's an up dip leg and a down dip leg, so at 180 degrees away from each other, but they're right next to each other on the same drilling pad. So while you're fracking one well, you're doing the wireline work on the other well, and you go back and forth. It's not a zipper frac, per se, but it's just alternating fracking versus wireline work, and that in itself saves you money, also.

We think we know how to do this and do it well. As I've repeatedly said, we've got a good drilling contract with [BHP], and we have what we consider very outstanding frac company at C and J, and they know how to frac wells.

On the Eagle Ford savings, of the $7 million you all noted, about how much of that is in completion and how much would that shift if you didn't have a C and J contract?

I'd say probably half of it is on the completion side and half of it is on the drill. At the end of the day, we'll probably have around $2 million into drilling, $2.5 million, and the other $3.5 million to $4 million tied up on the completion side.

Was there a part B to that question, I'm sorry, I forgot.

Yes. If you guys didn't have that C and J contract in place, what would that $3.5 million to $4 million go to?

It probably would be $5 million to $6 million, if I had to make a guess. Plus, the biggest problem is delays in getting pumping equipment. I mean, that kills you of course, and we've got $2.5 million, $3 million tied up on the drilling side, and the well is sitting there for multiple months.

All right. That's all I've got. Thanks, guys.

Thank you.

Adam France, 1492 Capital.

Baird, could you run me through what you would hope if you go back into east Texas and look for the Cotton Valley, what those wells cost, the reserves, what kind of IRRs.

Yes, certainly. We model these things about 4.5 Bs equivalent, including post-processing liquids. On a drilling completion side, we're probably talking around $5 million to $5.5 million. We have a slide in our presentations we use that shows that I think at an $85 oil price, and that it takes a $2.54 gas price to generate a 10% before tax rate of return, so if you take into account $4, $4.50 gas price, and use $100 oil for instance, we think the rate of return is easily north of 20% after tax.

Okay. Very good. Thank you.

You're welcome.

And that does conclude our question and answer session. At this time I'd like to turn the call back over to our speakers for any closing comments.

We thank you for participating, and I hope I did well my first call, and look forward to the next one. We thank you very much.

And that does conclude our conference. We appreciate your participation.