西南能源 (SWN) 2012 Q1 法說會逐字稿

Greetings, and welcome to the Southwestern Energy First-Quarter 2012 Earnings Teleconference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation.

(Operator Instructions)

As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Mr. Steve Mueller, President and CEO. Thank you, Mr. Mueller. You may begin.

Thank you; and good morning, and thank you for joining us. With me today are Bill Way, our Chief Operating Officer; Greg Kerley, our Chief Financial Officer; Jeff Sherrick, Senior VP of Corporate Development; and Brad Sylvester, our VP of Investor Relations. If you have not received a copy of yesterday's press release regarding our first-quarter 2012 results, you can find a copy on our website at www.SWN.com.

Also, I would like to point out that many of the comments during this teleconference are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control and are discussed in more detail in the risk factors in the forward-looking statements sections of our annual and quarterly filings with the Securities Exchange Commission. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and actual results or developments may differ materially.

Let's begin. We had a good quarter. Production grew 16%. Costs remained low. Our balance sheet was strengthened, and we have improving results in our Brown Dense play in Southern Arkansas and Northern Louisiana. Stopping the summary at that point ignores the elephant in the room, the gas price clouds casting dark shadows over our entire gas industry investments. We continue to respond to the current prices.

Only the best economic wells are being drilled in the Fayetteville Shale project, and we've continued to add firm capacity in Marcellus to ensure getting the gas to the most liquid points of sales. In addition, we have revisited our capital budget again, and are moving at least $50 million from our development activities in midstream, to accelerate drilling and leasing in our new ventures projects. Our goal is to understand the potential for both Brown Dense and Colorado plays by year-end. Our simple machine continues to perform and we're excited about how 2012 is unfolding.

Moving to our operating areas, we placed 146 operated wells on production on Fayetteville Shale during the first quarter. After announcing this play almost eight years ago, we surpassed the milestone of 2 Bcf a day, gross operated production, in April; and on May 2, we surpassed the milestone of cumulative gross production from the play of 2 Tcf of natural gas. My heartfelt thanks and admiration go to the many employees at Southwestern Energy, who over the years have made and continue to make this possible.

Our operated horizontal wells are at an average initial production rate of 3.3 million cubic foot per day, and average completed well costs of $2.8 million per well, with an average drilling time of 7.3 days during the quarter. We also placed 26 wells on production during the quarter that were drilled in five days or less. Looking ahead, we will continue to target the best wells in the field, and expect our initial producing rates will increase over the next several quarters, as we continue to high-grade our drilling program in Fayetteville Shale.

Also in April, we placed the initial orders for two fracture stimulation spreads that will be operated by the new subsidiary, called SWN Well Services. Delivery date is expected in the fourth quarter, and initially the equipment will work in the Fayetteville Shale. Each crew will be able to frac between 100 and 120 wells per year, and savings of approximately $200,000 per well are expected on the wells fracked with SWN's equipment.

In Pennsylvania, we have 24 operated Marcellus Shale wells located in Bradford County that are producing, and net production from the area was 9.3 Bcf in the first quarter of 2012, which is up from 2.8 Bcf in the first quarter of 2011. Gross operated production was approximately 122 million cubic feet of gas per day at March 31. We also began selling gas from our Price area in Susquehanna County earlier this week. Our first well, the North Price, number 5H, was put to sale on Tuesday, and everything looks very encouraging.

The rate yesterday was 3.9 million cubic foot per day on a 1664 S choke, with 3,000 pounds flowing pressure and 3,300 pounds casing pressure. The casing pressure is indicative of very little drawdown at these rates, so we will proceed with opening the well up slowly over the next few weeks. Now that this line is in place, we'll begin to see other wells in the area placed on production throughout the rest of the year.

In April, we entered into a new 15-year firm transportation agreement on the Constitution pipeline, with a total capacity scaling up to 150 million cubic foot per day. This project is expected to be in service by the second quarter of 2015. With this announcement, we currently have firm transportation and sales agreements in place for 325 million cubic foot per day at the end of this year, 2012; 517 million cubic foot per day by the end of 2013; 557 million cubic foot per day by the end of 2014; and 707 million cubic foot by the end of 2015.

Finally, the Bluestone Pipeline is progressing well, and we believe the north end of the line, which will transport gas from a range trust area in Susquehanna County, will now be in service no later than September of this year. The southern end of the pipeline is on schedule to transport gas from a Price area in November. In our ArkLaTex division, we produced 8.2 Bcfe during the first quarter, and earlier this week, we closed on the sale of the oil and natural gas leases, wells, and gathering equipment in our Overton Field in East Texas, for approximately $175 million.

The proceeds from this sale will be used to facilitate potential like-kind exchange transactions pursuant to Section 1031 of the IRS code. We incorporated the sale of Overton into our production guidance back in February, so we continue to guide total SWN production of 560 to 570 Bcfe for 2012. As for our new ventures, we hold approximately 3.6 million net undeveloped acres, of which 2.5 million acres are located in New Brunswick, Canada.

In our Lower Smackover Brown Dense play in Southern Arkansas and Northern Louisiana, we hold leases on 540,000 net acres and have drilled three wells in the area. Our first well, the Roberson, located in Columbia County, Arkansas, was placed on production in February and its highest producing rate was 103 barrels a day of 36-degree API gravity oil with 200 Mcf per day of gas. The well is then shut in for pressure buildup testing in March, and we continue to perform testing on the well, which includes recompleting one stage in the heel of the well with acids last week.

Our second well, the Garrett, located in Claiborne Parish, Louisiana, was placed on production in late March, and its highest-producing rate was 301 barrels of 52 API gravity oil, with 1.7 million cubic foot per day of gas, and 2,200 barrels of flowback water. Approximately 55% of the frac's fluid has been recovered to date. All the production to date has been through casing. We finished running tubing in the well yesterday, and opened the well back up this morning, and believe that the production will continue to increase until fluid recovery reaches somewhere around 65% of total. This should happen somewhere towards the end of May.

Our third well, the BML, located in Union Parish, Louisiana, was drilling out of the curve in late March when we received a pressure kick, which resulted in sticking the pipe. We then sidetracked the well and are currently drilling over 4,000 feet in the lateral. In our first attempt, we were drilling with 11.4 pounds per gallon mud, and during the kick, it increased the mud weight to 15.6 pounds per gallon. Data indicates the kick was an oil kick. The side track is drilling with an average mud weight of 15.4 pounds per gallon. We'll fracture-stimulate this well with approximately 30 stages later this month.

As I mentioned earlier, we want to accelerate testing in the Brown Dense, so we have decided to shift some capital away from our other operating areas, and currently we are evaluating adding another rig to the area sometime in the third quarter of 2012. We also hold 264,000 acres, up from 238,000 at year-end, in the DJ Basin in Eastern Colorado, where we began testing our new unconventional oil play targeting middle and late Permian to Pennsylvanian carbonates and shales.

In April, we spud our first well in Adams County, Colorado, and it has reached total depth of 9,543 feet in its current logging. We have already taken 90 feet of core, and once the vertical well is logged and evaluated, we plan to drill a 2,000-foot lateral, which will land in the Marmonton formation. The rig will next move and drill the Staner 5-58 #1-8, located in Arapahoe County, to a total vertical depth of approximately 9,000 feet.

In closing, we continue to invest in quality projects and innovate both in ways to develop new ways to drive down costs and find new opportunities to vest in. We have done this in the past, and we'll continue doing this in the future. Our Brown Dense and Colorado plays are just additional steps in that innovation process.

I will now turn it over to Greg Kerley, our Chief Financial Officer, who will discuss our financial results.

Thank you, Steve, and good morning.

We reported earnings for the first quarter of $108 million, or $0.31 a share, down from $137 million, or $0.39 a share in the first quarter of 2011, as lower gas prices offset the positive effects of our production growth. Our discretionary cash flow was $371 million in the first quarter, compared to $392 million for the same period in 2001, and reflected our strong hedge position in 2012.

Our average realized gas price of $3.49 per Mcf was down 15% from the same period last year, while the year-over-year spot gas prices were down approximately 39%. Our realized gas price, including gains from our commodity hedging activities, which increased our average price of $1.25 per Mcf during the first quarter. For the remainder of 2012, we have 200 Bcf of our gas production hedged at a weighted average floor price of $5.16 per Mcf.

Our commodity hedge position, along with cash flow generated by our Midstream Services business, which is not dependent on gas prices, provides us the solid protection on approximately two-thirds of our expected cash flow for 2012. Operating income for our EMP segment was $116 million during the quarter, compared to $178 million in the same period last year.

Our cost structure continues to be one of the lowest in the industry, with all-in cash operating costs of $1.31 per Mcf in the first quarter, which included approximately $0.04 per Mcf related to one-time catch-up expenses primarily related to the new Pennsylvania well impact fee. Those costs include our LOE, taxes, G&A and interest expense. Operating income from our Midstream Services segment continues its strong growth, as it increased by 29% in the first quarter to $69 million.

The increase in operating income was primarily due to the increases in gathering revenues from our Fayetteville and Marcellus Shale plays, and at March 31, our Midstream segment was gathering approximately 2.2 billion cubic feet of natural gas per day, through 1,800 miles of gathering lines in the Fayetteville Shale play, compared to gathering approximately 1.9 billion cubic feet per day a year ago. Our planned total capital investment program for 2012 of $2.1 billion is front-end loaded in the first two quarters. So in the current price environment, we would expect a decline in our capital investments during the third and fourth quarters of the year, along with a heavier weighing towards testing of our new ventures oil plays.

In March, we privately placed $1 billion of 10-year senior notes at an average interest rate of 4.1%, further strengthening our balance sheet and our liquidity. With this placement, we currently have nothing drawn on our unsecured $1.5 billion credit facility, and had cash on hand at the end of the quarter of around $200 million. And on May 1, we closed on the sale of our Overton properties, for approximately $175 million, further strengthening our liquidity.

Our capital structure continues to be in great shape, with a net debt-to-book capital ratio of 25%, on par with where we were at the end of 2011; and our net debt-to-market capitalization ratio is a low 13%. Looking ahead, we will continue to respond to current gas prices and are focused on reducing our costs even further, and are keeping our balance sheet in good shape.

That concludes my comments, so now we'll turn it back to the operator, who will explain the procedure for asking questions.

(Operator Instructions)

Brian Lively, Tudor, Pickering and Holt.

The Fayetteville 30- and 60-day rates for the wells drilled in the first quarter seem to be a little bit lower than prior periods. Was there any surface reasons for that, or do you think that that will be the trend we see going forward?

There weren't any surface issues. You've got to remember that if you think about what we did up until mid-last year, for the most part we were drilling one and two wells per section, and then towards the second half of the year, we were doing all pad work. I think what you're seeing is that the fact that you're drilling on much tighter spacing and a little bit of interference between wells.

We've talked about in the past, that all the curves we've shown, as you look out in the future, whatever lateral length we average, you need to take about 10% off of that, and you won't see it so much in the IPs, but you'll start seeing it in the 60 days. I think that's what you're seeing. Now, as you look out into 2012, it's going to be confusing, and by that I mean because we've gone back almost to drilling only a few wells off a pad and drilling the very best, and we've also gone to Whiting spacing to make sure we've got the best wells we can possibly drill, you're going to see the IPs 30s and 60s potentially set records before the end of the year.

And what that is, is nothing more than our strategies to drill the very best well. I think you're just seeing a little bit of what would have been the normal trend, with the 30 and 60 days you see now and it's going to get actually better, but a little bit out of whack as we go through the rest of the year.

Okay, that's understandable. Then on the Brown Dense, just two general questions there. One, what are the current well costs? And what are you trying to get to? Secondly, from the pressure buildup work that you're doing, just interested to see what kind of data you're trying to glean from that, what kind of reservoir information do you think you can obtain from the well, considering it had low rates and probably low accumulative production before you shut it in? And I'll hang up. Thank you.

As far as the well costs go, we've always talked about the first four wells for sure will be science wells. And by science wells, we're coring, we're drilling the vertical, we're doing a lot of extra logging. Because of that, there are easily $2 million of excess capital that we don't think will be a run rate. So the first part of the question was what's caused to the wells now.

They are running somewhere in the mid-$10 million to $12 million range, depending on exact depth and lateral length. We think we can get that well under $10 million and we still haven't gotten past getting down to $8 million. I'm not 100% sure we can do that today, and the reason I say that, this most recent well we drilled had some higher mud weights in it, which means you have to run another string of pipe. If we have some higher mud weights in part of the play, they will have to be a little bit higher costs from that standpoint.

Pressure.

Oh, yes. On the pressure, you'll see us do this on all these science wells. One of the keys to evaluating the reservoir is understanding what that initial bottom hole pressure is. This first well, once we got it cleaned up reasonably, we wanted to get the bottom hole pressure on it. You'll probably see us on the second well at some point in time in the future shut-in and do bottom hole pressure, and that's just a key piece of information in all the other science, there's nothing more to it than that.

Bijou Perincheril, Jefferies & Company.

Couple of questions. Steve, can you give us some additional color on your thought process behind bringing in the second rig in Brown Dense? Is it because there is fewer third-party wells planned and you think there has to be more Southwestern wells to delineate this play within a reasonable timeframe, or is it really the data points that you're seeing giving you more encouragement?

Well, I don't know about the more encouragement part. We are encouraged and we continue to be encouraged. The -- there's a minor amount of -- you have to get a lot of information and depending on how much the industry gets you makes a difference on how you drill.

I think the major reason, though, if you think of what we did in the first three wells, we started up in what we knew was going to be a heavier-gravity oil, 30 to 36 gravity, that'd be a good well, but then we went deeper and deeper with the second and third wells and new gas should be higher because you're getting higher temperatures, and we wanted to see if the rock would stay the same and what the right gravity window would be to get the best production.

What's actually happened is -- second well, you see a higher gravity, you see a higher gas rate. The third well has surprised us in that it's much higher pressures than we expected. As we look out, it may not be as simple as just you've got this gradient going north-south and picking the best spot within the gradient. We decided we want to learn faster and to learn faster, you have to drill faster. That's the main reason for what we're doing.

Okay. With this higher pressure area that you're seeing with the third well, do you have information to know at this point if that's something isolated, or if that covers a wider area? Can you give us some color on the additional leasing that you're doing now? Is that play moving to the east?

Well, as far as the pressure goes, there's been now almost 35 or 36 wells total drilled into or through the Brown Dense over the years, and that 15.6 that we saw, or had to kill that well with, was the highest anyone's ever seen. There has been one or two other wells that have been a 13 pound mud range, but most haven't been able to drill through with 12. So I have no idea how big an area it is, because we just -- from everything we saw, we really didn't expect to see that. I don't remember what your second part of your question was.

I was wondering where you were leasing --

Oh, lease. I would say most of that leasing that we've done is cleanup work, where if you followed us since the time we've announced the play, we've added about 20,000 acres a quarter. All that was, was from six months before, we signed an agreement, someone finally got all the title work done and handed them the check and then counted it as leases. I would expect for the next couple of quarters you'll see that happen, but I can tell you there's not any certain area we're concentrating on. We're still picking up and cleaning up across the whole 540,000 acres.

Okay, and then one last question. Did you get a BTU measurement on the last well, on the gas?

On the second well?

Yes.

Yes, it was roughly 1,250 BTU.

Okay, perfect. That's all I had.

Brian Singer, Goldman Sachs.

In the Marcellus, can you add some geographic color on your wells that you've completed so far with greater than 12 stages? How you're thinking about where you're drilling within your acreage going forward, and how gas price-dependent your overall rig count plans are for the Marcellus?

I think as far as the gas price dependency, as long as you look at the forward curves that we have out there, we're happy with the plan that we put together in the Marcellus, where we were going to go from basically two rigs running today to later this year running four rigs.

Most of the drilling in the first quarter was in Susquehanna County. As I said in my remarks, in the southern part of Susquehanna County, that's what we call the Price area, we put our first well in production. That was a line that our Midstream company laid down to the Tennessee gas line and it's going that direction to go out. We have -- and I don't remember the exact number, I believe we have three other wells in that area right now that are at TD and are in some stage of completion.

Then we have a rig drilling in the range area, which is the Northern Susquehanna block, and that's in preparation for that DTU line that's later this year. We have just, in the last week or so, fracked a well up there and begun a little bit of testing, but you won't see any sales out for a while.

What we've been doing most this quarter is getting ready for these pipelines to be put in the next couple of quarters. You will see, during the year, some wells being drilled back in Bradshaw -- Bradford County in what we call the [Greenswig] area. We still think for the year we'll drill about 75 total wells. Susquehanna will end up with about 44. Bradford County will have somewhere around 19.

You'll see the first rig that comes out this summer is the third rig moving into Lycoming County area, and we're looking at 10 to 12 wells in Lycoming County. That will be the next place we move to that we'll start getting some information on. That area -- there is a Penn-Virginia line that we have signed to get gas out of. We have also signed with them to get water. It's just a matter of getting the rig there and starting to do the drilling.

Okay, thanks. Secondly, in your decision to add the second rig, the Brown Dense, where do you plan to position that geographically, relative to where your first rig would have been drilling, or is drilling?

Well, right now, we're permitting at least four additional locations and we've got one location already permitted on the Arkansas side. All four locations we're working on right now are in Louisiana. Now, some of them are barely in Louisiana. But that rig, if we decide we need to put it to work here, it would be something around September-October timeframe. It would be whatever's next up on our list to drill. Each well that we drill, we try and learn from the one that's one before that. Right now, we're permeating enough wells so we can test several different things.

Great, thank you.

Scott Hanold, RBC Capital Markets.

On that third Smackover well, just to needle into it a little bit more, you said you had a surprising kick. It seemed to be more of an oil kick. Can you give us a little bit more color on that? Is it something geologically you're seeing that's a little bit different or interesting that could be encouraging?

I don't know about the encouraging part. Certainly, having oil and knowing you have some oil in there is encouraging, and I can give it a little more color. We drilled the well vertically. We did not take a whole core in this well, we actually took some rotary cores. We've looked at the rotary cores and it looks like there's some fairly good porosity and permeability, at least comparable to some of the other good porosity and permeability seen in some whole cores.

When we were drilling this well, as we were in the horizontal, or just about to get to the horizontal portion, we did take this kick. The reason we think it's an oil kick is that while we're drilling the oil base mud, we saw some gas increase, but our ratio of oil in our mud increased significantly. The way an oil kick acts, or as liquid kick acts differently than a gas kick and it certainly worked out of the system like an oil kick. So that's the evidence for having the oil portion. We're drilling right now.

While we've been drilling roughly 15.4 pounds per gallon, we have lightened the mudway up one time to see if that was just a fluke, or if there was, in the side track, if we had the same thing. And when we lightened the mudway up a little bit, it wanted to start flowing, so we went right back to the 15.4 pounds per gallon. How big an area it is, what it means, all I can say is higher pressure usually is better, because you can lift more fluids faster.

We think we've got some oil in it, but we're just going to have to get the well to TD and then figure out if it's just a single fracture or a couple fractures giving us the pressure, or is it something different about the geology when we go down there. Again, if you just look at logs or the little bit of core data we have, it's thicker. There has some good porosity and permeability in it, but there's nothing that grabs you and says this is going to be any different than anything else we have done in the past.

Okay. On the second well, why is it taking so much to get the water load off, 48 days at the peak? Is there a reason for that? Is it a pressure issue? Is it -- can you give us some sense of why that is?

Well, we've been very careful with how we flowed the well back, in both first and second wells. Part of it has to do with just how we're doing it. We're not opening those chokes up very fast as we're going through, we're just slowly letting it work its way up. Part of that is to understand how it's going to produce. Part of it is to understand something about the pressure characteristics on it. When we do modeling, in any of these horizontal wells, the first oil, first gas you get back is part of the lateral closest to the vertical.

The very toe-end of the well's the last part you get back. When we do the modeling as is it sits today, we think the last couple stages aren't even contributing yet at all to the oil rates. We haven't even got near enough water off them. That's why we said we need to get more of the percent back, but the reason it's taking a period of time is we're taking the time, it's not necessarily -- We probably could have opened up and got back faster, but we still think we need over 60% back.

Dave Kistler, Simmons and Company.

Real quickly, back to the Fayetteville just for a second, in the past you had highlighted at $4, at about 8,000 locations, $3, 1,100 to 1,200 locations. Given the current price environment, let's just use $250. How many locations would that represent at this point?

If you said it was $250 flat forever, not many. And I don't know what it is. Maybe $200.

Okay.

If you think about how you make decisions on wells, it's really the first four years to five years that count. When you look at the average for the next three to four years, it's forward curve. It certainly has a lot more wells than just a few hundred we're talking about.

Okay, that's helpful. Flipping over from that, then, to the rig count in the Fayetteville, you've been bringing that down and obviously that's kind of what's influenced the change in CapEx. But as you look forward, how low can you take that at this point and what's the contract obligations that you have on any of those rigs?

We really don't have any contract obligations on the rigs. All the rigs that we're using are our rigs. We can lay those down, when we want to lay those down. One of the rigs, if you remember, we started the year, the first day of the year with 12 rigs. Soon after the first of the year, we dropped down to 11. Today, we've got eight and we'd always talked about exiting the year with seven. We actually dropped down to eight a little faster, that's where part of this $50 million is coming from.

Some of that is that we're drilling a little faster than we thought we were going to be. We think we'll get still, when it's all done, the 400-plus wells, but we may drop the rigs a little bit faster. On a side note, one of the rigs we dropped recently is actually working for the first time for a third party, so to the extent that we can put those to work third party, you may see some of that. We've got one rig that's moving up to Pennsylvania to do some work up there also. They will continue to move around.

As far as any of the other services, we supply our own sand, so we can go at any pace we want to do there. On the frack side, on stimulation, while we have one-year deals, it's a percent of business. It's not a guaranteed business there. Whatever number of wells we drill and give to that, whatever that group is that has it, that's what happens. You could scale down as much as you want to.

Great. I appreciate the clarification, guys.

Credit Suisse.

Yes, Steve, I wanted to elaborate a little bit on the Marcellus. I know your gross operating production was down sequentially. I think that's just a function of the fact that you're only able to put two wells under production. It looks like your backlog of wells that haven't been tied in is up to 70. Can you just maybe give us a road map, given the infrastructure or pipelines that will be added, how production in the Marcellus could shape up? Because you do have a lot of wells waiting on the infrastructure.

Right. We've talked about this in the past, that the first quarter we didn't have much activity that was going to happen that would add to our take-away capacity. Back in the, say, November-December timeframe, we were hoping to have an additional compressor put on in our Greenswig area in the first quarter. Those permits took a lot longer to get than we thought.

As a matter of fact, it took us almost 18 months to get the permits. We haven't got the final, final one yet, but as you think about it, we just tied in a pipeline today, which is right -- or it was last week, within a week of being on schedule to tie us to Tennessee gas to help us with price. You start seeing those wells be completed and put on.

That compressor I'm talking about is set to go in in June and that will allow us, we start talking about the 24 wells in our production, about half of those are flowing into basically the pipeline pressure at 1,100 pounds and the other half of that's on compression at any point in time, that will allow us to put more of those on compression and start getting some more gas out that direction.

The next big data point or big take-away point is that early September, or middle of September point, on the Bluestone line, where we can start taking gas out of the range area. Ultimately, the take-away on that Bluestone line is 200 million a day, just on that line, either go to the Millennium or the Tennessee gas.

You won't get that immediately. It will take you 20 to 30 days to get to the line smoothed out, but you'll see us very rapidly start adding production going into the end of the year. We've talked about in the past that we would exit the year in the 300 million a day range and we're very comfortable that will happen, and we're very comfortable that we can hit our guidance for total company as well in production.

Got you. So you're just this lower start, but you're still on track--

Yes, we're on schedule and like I said, the first quarter wasn't going to have much. We knew during the first quarter, and we always talked about in the second quarter, we could jump it up to about 150 million a day. We're maybe a month behind on that, but we'll catch it up.

Okay. Steve, just switching gears back to the Brown Dense, the Cabot well, I think your well, was about 3 1/2 miles southwest of their well, and I think their rate was just around 200, 206 barrels. Any learnings from that well that you could speak to?

Yes, we have been sharing some data. I don't have as much information on that well as we do on ours. I think they landed it similar to us. Of course it was a shorter lateral. It was something less than 4,000 feet, or right around 4,000 feet.

Our second well is about 6,500 feet. When you get into the fracks, I don't think they put the frack stages quite the same in the perforation level quite the same as us. But in general, I think they were similar in how they drilled and the rock they were drilled into.

Okay, and last question. Steve, on the last call, you mentioned that the permeability between the lower and upper zones could be about five times -- there could be five times difference there. Any comments on the most recent wells, and any H2S you've seen in this most recent well?

We haven't seen hardly any H2S at all. Actually, we saw less H2S in this well than we did in the first well. We saw a couple days where it spiked a little bit and then didn't see any in the first well. This one, we haven't seen hardly at all. There is a trace, and when I say a trace, it's just a touch of C02 at times in this well. As far as permeability goes, I haven't actually -- no one's actually seen, we haven't got the actual perms calculated from the lab yet on the core in the second well.

When we look at flourescents, the first well in the upper half actually had better flourescents than the second well did in the upper half of that. Sometimes fluorescents, you can tie to permeability, sometimes it just has to do with the fluids and what's in the rock as well. We're still trying to sort that out. I really don't have a good answer for you. When you look at logs in the second well, the top half is better than the bottom half, just like I described before, but we got to tie those logs into the core data and we just don't have that data in yet.

Okay.

Amir Arif, Stifel Nicolaus.

Steve, can you just give us a sense of how many wells by year-end will we have drilled and how many we will have tested in the Brown Dense, as well as in the DJ?

That's going to be fluid. You could drill a well in either one of those, the next well and decide there's some critical factor that didn't work and it's done. But assuming that we continue to learn what we have, for instance, in Brown Dense, where we see each well getting a little bit better, I would guess that we're going to end up with about six to seven wells this year.

As I said, our goal would be to have that complete understanding by the end of the year, so we know if this thing is going to work or not. Now, that's the goal. Whether we can get there or not, it depends on if the rocks is like we think it is and depends on if it flows like we think it's going to flow and that kind of thing.

In Colorado, the first well we're drilling, we're going to land that in the Marmonton, which is very top of the objective section that we're looking at. The second well, we're certainly going to look at the Marmonton interval, but we think that a deeper interval in the Atoka section may get better there and if it gets better, then we have to sit back and look at, basically, is it as good as the Marmonton, or how do they compare?

How do you have to test the two or if it's not better in one zone as you go through? There's some decisions to be made after the second well in Colorado. That's why we'll have a short gap and then we'll go back to drilling whatever we learned from those first two wells.

Okay, and a second question is just in the Brown Dense. As you went from the second to the third well, your lateral's coming down quite a bit, but you're doing a lot more frack stages. Are you simply trying to get the economics in terms of production per frack stage to make the economics work, or are you looking for some operational improvements by doing so many fracks?

Yes, the -- if you remember, we originally targeted 9,000-foot lateral in that third well, and when we took that kick, without going into a lot of technical details, the shoe that we had was set as fairly deep, our casing shoe was set fairly deep. But it probably wasn't in good enough shape to allow us to drill a well at 15 pounds or higher mud weight. So we actually set an extra string of pipe.

Since we haven't planned for that spring of pipe, it causes us to drill with a smaller drill string. The physical limits of drilling, we can't go 9,000 feet anymore. We can only go about 4,000 feet. We're going out as far as we can with the way this well is set up. That won't affect us in the future, because we'll just plan for it in this area in future and we are going to get whatever lateral length we want. As far as the number of stages, we're trying to get some end-member tests, so in the -- as I talked about before, the first four wells is science.

First couple, we fracked the exact same way, just to see what lateral length would do. This one, we were planning to do 9,000-foot lateral with a bunch of fracks on it. We're doing 4,000-foot lateral with a bunch of fracks just to start understanding how close you could put the fracks together and what the effect of that is. It's just part of the science we planned.

Okay, thank you.

Michael Schmitz, Ladenburg.

Steve, you mentioned you didn't think all of the frack stages are contributing yet in the second well. Can you quantify how many frack stages you think are actually contributing?

Well, it's just modeling. We don't have any way of going down, at least easily, and trying to figure out at this point in time what's contributing from each stage. At some point, we will do that once it's cleaned up. When you just look at the models and look at how much fluid you've taken out and the drawdown you've had across there, it looks like out of that roughly 20 stages, 19 stages we have, that the farthest one out isn't contributing hardly anything yet.

Then it grades, but it would be three to four of those that are still cleaning up, and some portion of it, the fourth closes in, probably starting to just start to contribute some oil and as I said, the farthest one out isn't contributing. Now, the -- one of the things we have to learn is we talk about lateral length, is can you actually clean up a well? You've got all these models, but then is it actually going to clean up the way you think it's going to clean up, and certainly part of the whole design of lateral lengths are, you want to have a well to completely clean up.

Part of the 6,000 and part of the 9,000 we're talking about was just understanding with this rock and this environment, if you drilled a 9,000-foot lateral, could you ever even get it cleaned up, or if you drilled a 6,000, could you get it cleaned up? That's something we're learning right now. But three to four stages are still in some portion of cleanup stage.

And as a follow-up, on the Fayetteville, did you say that given the high grading and drilling the wells wider spacing, that you expect both the IPs and 30s and 60-day rates to set records this year in the Fayetteville?

They could. I'm not going to go say expect it, but it certainly looks like they could.

Okay.

Robert Christianson, Buckingham Research Group.

I'm curious on the second well as to the frack heights, I mean on the first well, I think they were 100 to 150. Did you ever get some research on the frack heights on the second well?

We really don't have any data on that right now, to tell you the truth. We did not do my microseismic on the second well. It's really just indications from flowback. That's all it is right now. As I've talked about in the past, when we fracked it, you've got some models that you use for pressures and things as you're fracking to see if it's growing the way you think it should grow.

When we fracked it, very consistently, it worked like the model said it would, but as far as understanding if you actually got across the entire zone, we don't know. The reason that's important, since this is about 400-foot thick in the second well, to get 200-foot above and below a well is kind of the limits in most cases for frack. So whatever we're doing, we're kind of pushing the limits, and we'll have to, in some future wells, better understand that part, Bob.

Coming back to the first well, curious as to why you're going to fracture stimulate what, one stage of it?

We're isolating -- I don't know that we're just doing one when it's all done. We're doing one right now, but we've isolated some of the frack intervals that we had, and what we've done, the closest one to the vertical part of the well was also on the best part of the rock in the first well.

We started with that one. We've gone into it, isolated that, put packers around it, and then we've actually put some acid on it. We haven't used any acid in any of the fracks we've done to date and we wanted to see two things. We wanted to see how that individual zone best-looking rock would flow, and also wanted to see what the effect of acid would be on it to help us design our frack intervals.

I could see, after we do that, depending on the results there, you might see us do something else in that first well and some other fracks. We're using that first well as a test well to help us set up the other wells down the road. That's all that's going on there.

And bringing in a second rig, what does that hinge upon? Does it hinge upon this third well? Is that the decision point, or is there another decision point?

It hinges on, really, two things. How fast we think we can drill wells, and then how much variation do we see? The mud weight in that third well surprised us. If we just took, as I said, the wells around there and the wells in the general vicinity, you shouldn't have that higher pressure.

If we drill a well, say, offsetting this one and it's got a super low pressure, you'll have to drill more wells to figure it out. If it ends up that there's some reason that you come up with why there's high pressure in one area, you can figure out where that is and then understand what the other part of the rock looks like fairly easily.

You'll get it done faster. So it's really just depending on if it's acting the way we think it's going to act and it's giving us the things we think it's going to do, or is it -- there some differences that are much greater than we expect and then we need to drill more wells to figure out those differences.

Just one open-ended question, Steve, if I might. What elements of encouragement should we have on the Lower Smackover Brown Dense with what knowledge you have today? Broadly speaking, I'm not sure that we have points of encouragement at this juncture as a readership crowd. What could you offer broadly speaking?

Yes, we're -- if you think about tests that are out there, there's three tests today. We've got two of them. You're seeing better production in each one of the tests. You can go into all kinds of reasons why it could or it couldn't be better, and you're seeing things that don't quite match a model, but they are not necessarily bad things yet.

You can find things that don't match the model that just says it's not going to work at all, but having higher pressure actually could help, seeing that, sure enough, as you go deeper in the section, you do have more gas that can help lift and now you can start worrying about where you find a window where you would have the optimum production, gives you encouragement that you could do some other things.

I think the biggest encouragement I have is we haven't run into anything that's making this thing go back the other direction. It's still going forward. And that doesn't mean we're going to get there. Doesn't mean that it's going to work, but we've got a lot of things we can do on it to make it work.

We could continue to be very excited about it and where we're at, at our two wells and Cabot's well, in the play right now is ahead of where I thought we would be, frankly. I thought we would have more issues and have more question marks, and we are going down learning paths. It just comes back to that's the fun of exploration. Every well is a little different and how you factor that in and what you do next on it.

Well, thank you very much.

Joel Allman, JPMorgan.

Steve, are not the production rates somewhat discouraging? I know you just said that you thought they might -- things are ahead of where you thought they would be, but are not the production rates discouraging? Is there anything else that you've seen that might be discouraging?

I'm not sure I would say the production rates are discouraging. You have to kind of think where I came from. I wasn't expecting hardly anything out of the first well and the fact that we got something we could work with quickly was very encouraging to me.

The fact that we added lateral length in the second well and got better rates when we did that -- if nothing else, we continue to add lateral length to at least part of this, until some of these other things I talked about keeps you from getting there. I think that continues to have encouragement there. I don't necessarily think that 300 barrels a day is a discouragement at all.

We didn't talk about it in the press release, but that 300 barrels a day wasn't a single-day rate for about 20 days, we were very close to that number, bouncing around that number. We know we can sustain that rate for a while -- get a better rate by doing various things that were out there. As far as discouragement goes, and this really isn't discouragement, but if there is an area that has this higher pressure, certainly higher pressure could help lift fluids out, but it will cost more.

One of the things we have to do on this third well is figure out, is it helping with whatever is going on? We talked about in the past, we thought in the play, we need about 500 barrels a day on a 30-day average rate to basically make all the economics work. You may reset that a little bit, depending on if there's an area that is pressured.

It may be a little more cost that you have to have, you are going to have to have a little bit more rate. It's not so much discouragement. It's just, we are going to have to learn, and this certain well will tell us, how much different it is than the first or second wells are.

That's helpful, thanks. And the second well, how much higher do you think that could go?

You know, I don't know. Maybe 20% higher, 10% higher. I don't know. 60 barrels a day.

Got you.

70 barrels a day.

Okay, thanks. And could you clarify, the $50 million or more capital, what are the differences between the original plan and the new plan that adds $50 million or more capital?

Well, without going into a lot of details, we're taking about $20 million out of the Midstream and (inaudible) Midstream and what's happened there is as we're high-grading to these very best wells, most of those locations are already built. Most of them have pipelines to them so we don't have to lay some of the pipe we thought we were going to do.

It's not just not doing some work by changing the game plan there. The other part of that is we moved one rig out a little faster in the Fayetteville than we had planned, and we'll probably move a second one out, probably go a little faster going down to that seven rigs that we talked about and that gets you most of the other. There's a little bit of corporate capital that comes out of that, too. We're taking it from areas that are not going to affect production this year and then what we're doing is we're applying it back to the new ventures.

It's really not -- it won't all go to Brown Dense -- a big chunk of it is going to Brown Dense, but there's some things we're trying to pick up some acreage on that we want to accelerate a little bit, then we'll make some decisions about Colorado. Really right now, we have the two wells in Colorado and what we see, we'll have some more drilling after that that's not really even counted in anything we are doing right now.

Got you. So will you be drilling more wells in the Brown Dense than you originally planned?

Yes.

Okay.

Or we are assuming we will.

Got it, and that, I assume, is bringing the second rig in, am I right?

Yes.

Very helpful.

Mike Kelly, Global Hunter Securities.

Following up, Steve, on your comments earlier that you're being diligent in terms of flowing these Brown Dense wells back, I was hoping you could give the choke size and really just give your thoughts, if it's even an appropriate exercise for us financial types here, to really make a read-through on the ultimate success of one of these wells based on these initial rates.

Yes, we've slowly opened the choke up. We start as low as 16 and I don't know where we're at now, but we're probably in the 42-something range, something like that on the choke size. But we just -- we'll go, like, four or five days, six days, then we'll kick it up a little bit, four or five days, kick it up and watch what happens with both your water and oil rates.

I think your second part helps the investors understand what we're doing. As far as the well goes, it's still making quite a bit of water, but that water rate has been dropping very rapidly in the last couple weeks. The oil rate as a ratio compared to the water rate has continued to incline. I know some of our internal discussion's been, will this have a lot of formation water? At this point, we haven't seen formation water.

We're still at the point where we're trying to determine what the final mix will be in the second well, how much gas will be there, how much oil will be there and what that final water rate would be, if there's any water rate. So that's all still working, but just the fact that the water dropped off hard here recently, oil's on a ratio basis is going up, as far as ratio basis is still cleaning up and we still have more to learn about what the well can do and how it can work overall.

Now, having said that, the other part you have to remember, it really doesn't matter what choke you started with, it doesn't matter what the peak rate is. It's what's a sustained rate you can have to get the target EUR that you have to have and, frankly, we just do not have enough information to be able to understand whether we can or can't do that yet. We're just going to have to stay tuned, and we are all going to have to watch -- we're going to probably need about six months production on three or four wells, not just a month and a half's production on one well.

Okay, great. Thanks. My follow-up, I was hoping you could talk about the competitive environment, pertaining to leasing. As it stands now on both the Brown Dense and the DJ Basin, and if you've seen a noticeable change in the amount of interest coming from operators now looking to get into the play?

You've seen a little bit of increase in the Brown Dense, mainly by some fairly small operators that have come in and taken some small blocks. But there's not been a big push, and I think part of the reason for the big push is we've got the real big block, so if you want to put a big push on the Brown Dense, you're going to have to work at it hard.

There may be somebody out there doing it, but we just haven't seen it at this point, or seen much of it. On the Colorado play, we continue to pick up acreage there, really haven't seen much competition, and I think, if anything, everyone's waiting for our wells to get down, or they are off doing Niobrara and they're not worrying about this play. Right now, both places may be up $25 an acre or something, but it's nothing significant.

Okay.

Jack Aydin, KeyBanc Capital Markets.

Steve, how much of a decision -- impacted your decision

Well, the mud weight and the kick in that third well was a surprise, so you then go back to the drawing board and try to figure out what you're going to do. Certainly the wells we're permitting now were not under original plan because it's like, okay, is this going to be a large area where there's pressure?

Is this a unique thing where there's pressure? You're starting to have to react to what you saw from a surprise, basically. Now, how close they are, there's some fairly long stepouts. They are not all just -- as a matter of fact, they are not all right around this well. I think the nearest one to this is probably eight to nine miles away, as we look at it, because the whole idea here is we don't know what we're going to get out of this well, let alone what we see on the next wells as we go through.

You'll see us integrate what we're learning in the third well and some locations we may not have thought about in the past, with locations we already had and we're already working on in the past. It evolves, as you learn, and that's what's happening right now.

David Snow, Energy Equities.

I had a couple of macro questions on shale. You made a point a few years back about compressing the learning curve and getting two years in Fayetteville versus, well, in total, 18 years. But I'm wondering, what is the average -- what do you think your average time is to evaluate a play and bring it to commerciality? And secondly, what odds do you put on the plays that you're looking at?

Yes, as far as how fast it takes to get something on, it depends a lot on depth and how fast you can get information. If you've got a shallow play, you can get information a lot faster than you can on deep wells. It also depends on how much the industry effort is in that play. If you think about a Haynesville well, it was deep and took time for each individual well, the industry very quickly ramped up to 180 rigs and basically could take that play from the first couple wells just learning about it to producing over 5 Bcf a day in three and a half, four years.

There's variables in there, and you can kind of see those variables. When you look at the Utica play that they are working on, those first Utica wells that people were talking about already are probably almost two years old, and you're just now starting to see that ramp up. And if that has to do with just the play in the area and how fast the industry jumps on it. I don't know if there's a answer to say how fast any average play would work. I will say that we're learning from each other.

The Fayetteville -- what we did in the Fayetteville, they first started doing in Marcellus, and they learned from that. What they did in Marcellus, what we learned from it, what we use in the Haynesville, what we use in all of these other plays, we're learning and using in Brown Dense in the Colorado. We expect that because of what's been done in the past, we'll be able to get up this curve fairly quickly and that's why we think we can make decisions on whether it's going to work or not by the end of the year and then you ramp up from there. As far as --

When did you start the Brown Dense to give you -- give us a benchmark on that one?

Yes, we came up with the idea almost three years ago now. We started leasing about almost two years ago, and then we spud our first well in, I think it was September, late September timeframe of last year. From a drilling standpoint, we've only been working on it now eight months, nine months, somewhere in that range.

As far as the risk on these plays we're working on, what we said from day one is that some plays are not going to work. What we want to do is test two ideas a year over a five-year period of time, have 10 ideas that we've tested, and two to three of those work and part of success comes to the size, also not just the fact that it produces commercial quantities. We said that those two to three, we want to be big enough to replace the Fayetteville Shale. I think we're on that track.

When you take a look at Brown Dense in the Colorado and we haven't talked about New Brunswick, what's going on in New Brunswick and other ones we'll talk about in the future, that's our goal. Any of these plays, the implicit chance of them working are probably between 20% and 30%. Now, certainly, as you drill, those will change as you're drilling and as I talk about before in Brown Dense, I think we're getting closer, but we're certainly not to the point where you can say yes, it's going to work yet.

Great, thank you very much.

Thank you. There are no further questions at this time. I would like to hand the floor back over to management for any closing remarks.

Thank you. I started the conversation today saying I thought 2012 would be exciting. It has been exciting. We're learning things daily and it's not just on the gas price side that we're learning things. We're learning things about what's going on in the field and how we're doing it. If there's anything about the Fayetteville Shale, we're drilling faster than we're ever going to drill. We're adjusting to that. We've increased our vertical integration and you start seeing the effects of that next year on the cost cutting side.

We've looked at it and are drilling the best wells and can drill wells that work in this economic environment. Marcellus, we continue to get the take-away we need to ramp up and if you think about last quarter, we talked about a maximum take-away of 500 million a day, today we're talking about 700 million a day in the Marcellus. Midstream continues to grow and Greg talked about how that was working and then you've got the new venture plays.

What could be more exciting than having a well at TD in Colorado, getting ready to side track it, having a third well in the Brown Dense and seeing differences, but also seeing progression as you go through the whole process. We're excited about the year, we're excited about the quarter. The last thing I want to mention here is we want to give thanks, and we want to give thanks to all of our investors.

I know a lot of you have followed us over the last eight years and it really is a milestone to hit 2 Bcf a day gross production and 2 Tcf produced out of Fayetteville Shale. Who would have thought seven, eight years ago that we would be selling Overton and that we would have produced 2 Tcf out of a play no one even heard about? I want to thank you for following us all this time.

And then I want to thank our employees one more time. The amount of work and dedication to get to this point is tremendous, and with the plays and ideas we have going forward and the many more years of Fayetteville and Marcellus, I know we'll have a lot more milestones on looking for those milestones. Thank you. We'll talk to you next quarter.

Thank you. This concludes today's teleconference. You may disconnect your lines at this time. Thank you all for your participation.