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Executives

Steven L. Mueller - Chief Executive Officer, President and Director

Gregory D. Kerley - Chief Financial Officer, Executive Vice President and Director

Analysts

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Brian Singer - Goldman Sachs Group Inc., Research Division

Scott Hanold - RBC Capital Markets, LLC, Research Division

David W. Kistler - Simmons & Company International, Research Division

Arun Jayaram - Crédit Suisse AG, Research Division

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Michael Schmitz - Ladenburg Thalmann & Co. Inc., Research Division

Robert L. Christensen - The Buckingham Research Group Incorporated

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Michael Kelly - Global Hunter Securities, LLC, Research Division

Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division

David Snow

Southwestern Energy (SWN) Q1 2012 Earnings Call May 4, 2012 10:00 AM ET

Operator

Greetings, and welcome to the Southwestern Energy First Quarter 2012 Earnings Teleconference Call. [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.

Steven L. Mueller

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've 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'd 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 and the forward-looking statement sections of our annual and quarterly filings with the Securities and 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 at that summary -- stopping that summary at that point to acknowledge 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 have continued to add firm capacity in the 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 the 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 the Fayetteville Shale during the first quarter. After announcing these plays -- this play almost 8 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 out to many of the -- to the many employees of Southwestern Energy who, over the years, have made and continue to make this possible.

Our operated horizontal wells had 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 are -- we placed -- we also placed 26 wells on production during the quarter that were drilled in 5 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 the Fayetteville Shale.

Also in April, we placed the initial orders for 2 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 frac-ed 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 #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 16/64" 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 will 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 770 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 our 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 scale -- on schedule to transport gas from our Price area in November.

In our Ark-La-Tex 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 net 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 3 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 has been shut in for pressure buildup testing in March, and we continue to perform testing on the well, which includes re-completing one stage in the heel of the well with acid last week.

Our second well, the Garrett located in Claiborne Parish, Louisiana, was placed on production in late March and is the highest-producing -- and its highest producing rate was 301 barrels of 52 API gravity oil with 7 -- 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 we'll open 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 down to 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 sidetrack 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 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 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 Marmaton 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 cost and find new opportunities to invest in. We've 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.

Gregory D. Kerley

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 (sic) [2011] 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 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 price, provides us the solid protection on approximately 2/3 of our expected cash flow for 2012.

Operating income for our E&P 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 onetime 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 2 quarters. So in the current price environment, we would expect to decline our capital investments during the third and fourth quarters of the year, along with a heavier weighting 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 hands at the end of the quarter 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 booked 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. And now we'll turn it back to the operator who will explain the procedure for asking questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question is coming from the line of Brian Lively of Tudor, Pickering and Holt (sic) [Tudor, Pickering, Holt & Co.].

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

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, like, surface reasons for that? Or do you think that, that will be the trend that we see going forward?

Steven L. Mueller

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're drilling 1 and 2 wells per section. And then towards the second half of the year, we’re doing all pad work. And so 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 this in the past, that all the curves we've shown -- as you look out in the future, whatever lateral length we average, you can 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. So 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 widening the spacing to make sure we've got the best wells that 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 strategy to drill the very best wells. So I don't -- I think you're just seeing a little bit of what would have been the normal trend with the 30 and 60 days you're seeing 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.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay, that's understandable. Then on the Brown Dense, just kind of 2 general questions there. One, what are the current well costs? And what are you trying to get to? And then secondly, from the pressure build-up 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 cumulative production before you shut it in? And I'll hang up.

Steven L. Mueller

Thank you. As far as the well costs go, we've always talked about the first 4 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. And because of that, there easily $2 million of excess capital that we don't think will be a run rate. So a -- the first part of the question was, what's the costs of the wells now? They're running somewhere in the mid-$10 million to $12 million, depending on the exact depth and lateral length. We think we can get that well under $10 million, and we talked about in the past getting it 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 has some higher mud weights in it, which means you have to run another stream of pipes. So if we have some higher mud weights in part of the play, they'll have to be a little bit higher costs from that standpoint. And on the pressure, you'll see us do this on all of these science wells. One of the keys to evaluating the reservoir is understanding what that initial bottom-hole pressure is. And so this first well, once we got it cleaned up, reasonably, we wanted to get the bottom-hole pressure on it. You will 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 out -- there's all the [ph] other science. There's nothing more to it than that.

Operator

Our next question is coming from Biju Perincheril of Jefferies & Company.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

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

Steven L. Mueller

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 -- and just 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 about what we did in the first 3 wells, we started up in what we knew was going to be a heavier-gravity oil, 30, 36 gravity, that would be good oil, 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. And the third well has surprised us in that it's much higher pressures than we expected. And so 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. And so we decided we want to learn faster, and to learn faster, you're going to have to drill faster. So that's the main reason for what we're doing.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Okay. And so 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? And can you give us some color on the additional leasing that you're doing now? Is that -- is the play moving to the east?

Steven L. Mueller

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 -- it was the highest anyone has ever seen. There has been 1 or 2 other wells that have been in a 13-pound-mud range, but most of them we've 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.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

I was just wondering where you were leasing...

Steven L. Mueller

I would say most of that leasing that we've done is clean-up work. We're -- if you've followed us since the time we announced the play, we've added about 20,000 acres a quarter. And all that was, was from 6 months before we had signed an agreement and someone finally got all 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.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Okay. And then one last question. Did you get a Btu measurement on the last well on the gas?

Steven L. Mueller

On the second well?

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Yes.

Steven L. Mueller

Yes. It was roughly 1,250 BTU.

Operator

Our next question is coming from Brian Singer of Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

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 then how gas price dependent your overall rig count plans are for the Marcellus?

Steven L. Mueller

I think -- I'll start with 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've put together in the Marcellus where we were going to go from basically 2 rigs running today to, later this year, running 4 rigs. Most of the drilling in the first quarter was in Susquehanna County. And as I said in my remarks, in the southern part of Susquehanna County, that's what we call the Price area, we've put our first well on production, and 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 3 other wells in that area right now that are at TD and are in some stage of completion. And then we have a rig drilling in the Range area, which is the Northern Susquehanna block, and that's in preparation for that BTU line. It's later this year. We have just, in the last week or so, frac-ed a well up there and begun a little bit of testing, but you won't be seeing any sales out for a while. So what we've been doing most of 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 the -- what we call the Greenzweig 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. And then you'll see the first rig that comes out this summer is that third rig moving to Lycoming County area, and we're looking at 10 to 12 wells in Lycoming County. So that will be the next place we move to that we'll start getting some information on. In 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, so it's just a matter of getting the rig there and starting to do the drilling.

Brian Singer - Goldman Sachs Group Inc., Research Division

And then 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?

Steven L. Mueller

Well, right now, we're permitting at least 4 additional locations, and we've got one location already permitted on the Arkansas side. All 4 of the locations we're working on right now are in Louisiana. I know some of them are barely in Louisiana. But that rig, if we decide we need to put it to work here, it'd be something around September, October time frame. It would be whatever is next up on our list to drill. Each well that we drill, we try and learn from the one that's one before that, and so right now, we're permitting enough wells so we can test several different things.

Operator

Our next question is coming from Scott Hanold of RBC Capital Markets.

Scott Hanold - RBC Capital Markets, LLC, Research Division

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. And can you give us a little bit more color on that? I mean, is it something you're -- geologically you're seeing as a little bit different or interesting that it could be encouraging?

Steven L. Mueller

I don't know about the encouraging part. Certainly, having the oil and knowing you have some oil in there is encouraging. And I can give you a little more color: We drilled the well vertically. We did not take a hole core in this well. We actually took some rotary cores, and we've looked into rotary cores and it looks like there's some fairly good frosting [ph] and permeability at least comparable to some of the other good frosting [ph] and permeability seen in some of the hole cores. When we were drilling this well, as we're 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 were drilling with oil-based mud, we saw some gas increase, but our ratio of oil in our mud increased significantly. And the way an oil kick acts -- or a 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 mud weight up one time to see if that was just a fluke or if there was in the sidetrack, if we had the same thing. And when we lightened the mud weight up a little bit, it wanted to start flowing, and so we went right back to that 15.4 pounds per gallon. So 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. And 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 of fractures giving us the pressure or is it something different about the geology when we go down there. Again, from -- if you just look at logs or the little bit of core data we have, it's thicker. They're -- it has some good frosting [ph] and permeability in it, but there's nothing that just grabs you and says this ought to be significantly different than anything else we've done in the past.

Scott Hanold - RBC Capital Markets, LLC, Research Division

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

Steven L. Mueller

Well, we've been very careful with how we flow the oil back in both the first and second wells, and so part of it has to do with just how we're doing it. We're not opening the chokes up very fast as we're going through. And we're just slowly letting it work its way up. And 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, the first gas you get back is the part of the lateral closest to the vertical, and then the very toe-end of the wells is the last part you get back. When we do the modeling, as it sits today, we think the last couple of stages aren't even contributing yet at all to the oil rates. We haven't even got near enough water off them. And that's why we said that 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 would -- probably could have opened it up and got back faster, but we still think we need over 60% back.

Operator

Our next question is coming from Dave Kistler of Simmons & Company.

David W. Kistler - Simmons & Company International, Research Division

Real quickly, back to the Fayetteville just for a second. In the past, you'd highlighted: at $4, you had about 8,000 locations; $3, kind of 1,100 to 1,200 locations. Given the current price environment, let's just use $2.50, how many locations would that represent at this point?

Steven L. Mueller

If you said it was $2.50 flat forever, not many. And I don't know what it is. It's maybe 200. But if you think about how you make decisions on wells, it's really the first 4 years to 5 years that count. And when you look at the average for the next 3 to 4 years, it’s a forward curve, it certainly has a lot more wells than just the few hundred we're talking about.

David W. Kistler - Simmons & Company International, Research Division

Okay, that's helpful. And then maybe 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 sort of the contract obligations that you have on any of those rigs?

Steven L. Mueller

We really don't have any contract obligations on the rigs. All the rigs that we're using are our rigs, and so 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, there were 12 rigs. Soon after that first year, we dropped down to 11. Today, we've got 8, and we'd always talked about exiting the year with 7. We actually dropped down to 8 a little bit faster. That's where part of this $50 million is coming from. And some of that is that we're drilling a little faster than we thought we were going to be. So we're getting -- 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. Kind of a side note: One of the rigs we dropped recently is actually working for the first time for a third party. And so to the extent that we can put those to work in third party, you may see some of that. We'll -- we've got one rig that's moving up to Pennsylvania to do some work up there also. So they'll 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 frac side, on stimulation, while we have one-year deals, it's a percent of business. It's not a guaranteed business there, so whatever number of wells we drill and give to that -- whatever that group is that has it, that's what happens. So you can scale down as much as you want to.

Operator

Our next question is coming from Arun Jayaram of Crédit Suisse.

Arun Jayaram - Crédit Suisse AG, Research Division

Yes, Steve, I wanted to elaborate a little bit on the Marcellus. I know your gross operating production was down sequentially, but I think that’s just a function of the fact that you're only able to put 2 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 roadmap 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 infrastructure.

Steven L. Mueller

Right. And we've talked about this in the past, that the first quarter, we didn't have much activity that's going to happen that would add to our takeaway capacity. Back in the, say, November-December time frame, we were hoping to have an additional compressor put on in our Greenzweig 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. And 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 up -- or it was last week, it was within a week of being on schedule to tie us to 10C [ph] gas to help us with price. You'll 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 -- when you start talking about the 24 wells that are on production, about 1/2 of those are flowing into basically the pipeline pressure of 1,100 pounds, and the other 1/2 of that is on compressor at any point in time. That will allow us to put more of those in compression and start getting some more gas out that direction. And then the next big data point or big takeaway point is that, early-September, middle-of-September point, on the Bluestone line where we can start taking gas out of the Range area -- and ultimately, the takeaway on that Bluestone line is 200 million a day just on that line either going to Millennium or the Tennessee Gas. You won't get that immediately. It will take you 20 to 30 days to get the line smoothed out. But you'll see us very rapidly start adding production going into the end of the year. So we talked about in the past that we'd 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 a total company as well in production.

Arun Jayaram - Crédit Suisse AG, Research Division

Got you. So you're just a slower start, but you're still on track for the 300 million a day rate…

Steven L. Mueller

Yes, yes. We're on one 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.

Arun Jayaram - Crédit Suisse AG, Research Division

Okay. Steve, just switching gears back to the Brown Dense. The Cabot well, I think your well was about 3.5 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, if you’re sharing data?

Steven L. Mueller

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. And of course, it was a shorter lateral. It was something less than 4,000 feet or right around 4,000 feet. Our second well was about 6,500 feet. And then when you get into the fracs, I don't think they've put the frac stages quite the same -- or the perforation there was quite the same as us. But in general, I think they were similar in how they drilled and the rock they were drilled into.

Arun Jayaram - Crédit Suisse AG, Research Division

Okay. And last question. Steve, on the last call, you mentioned that the permeability between the lower and upper zones could be about 5x -- there could be a 5x difference there. Any comments on the most recent wells? And any H2S you've seen in this -- the most recent well?

Steven L. Mueller

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 of 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 trace, it's just a touch of CO2 at times in this well. As far as permeability goes, I haven't actually -- no one's actually seen it. We haven't got the actual perms calculated from the lab yet on the core in the second well. When we look at fluorescence, the first well in the upper half actually had better fluorescence than the second well did in the upper half of that. And sometimes, fluorescence tie -- you can tie it to permeability. Sometimes, it just has to do with the fluids and what's in the rock as well. But 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've got to tie those logs into the core data, and we just don't have that data in yet.

Operator

Our next question is coming from Amir Arif of Stifel, Nicolaus.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

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

Steven L. Mueller

That's going to be fluid. You can drill a well in either one of those, the next well, and decide there was some critical factor that didn't work, and it's done. But assuming that we continue to learn, like 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 6 to 7 wells this year. And 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 can -- that's the goal. Whether we can get there or not, it depends on if the rock is like we think it is, and it depends if it flows like we think it's going to flow and those kind of things. In Colorado, the first well we're drilling, we're going to land that in the Marmaton, which is the very top of the objective section that we're looking at. The second well, we're certainly going to look at the Marmaton area, 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 a Marmaton or is it -- how do they compare, and then how do you have to test the 2 or, if it's not better, the one zone as you go through. So there are 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 learn from those first 2 wells.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

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 frac stages. Are you simply trying to get the economics in terms of production per frac stage to make the economics work? Or are you looking for some operational improvements by doing so many fracs?

Steven L. Mueller

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 hadn't planned for that string of pipe, it caused us to drill with a smaller drill string. And the physical limits of drilling, we can't go 9,000 feet anymore. We can only go about 4,000 feet. So we're going out as far as we can with the way this well is set up. Now that won't affect us in the future because we will just plan for it in this area in the future, and we’ll go get whatever lateral length we want. As far as the number of stages, we're trying to get some end member tests. So in a -- as I've talked about it before, those first 4 wells are science. The first couple, we frac-ed the exact same way just to see what lateral length would do. Now this one, we were planning to do a 9,000-foot lateral with a bunch of fracs on it. We were doing 4,000-foot laterals with a bunch of fracs just to start understanding the -- how close you can put the fracs together and what the effect of that is. So it's just part of the science we've planned.

Operator

Our next question is coming from Michael Schmitz of Ladenburg.

Michael Schmitz - Ladenburg Thalmann & Co. Inc., Research Division

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

Steven L. Mueller

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. But 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 the roughly 20 stages, 19 stages that we have, that the farthest one out isn't contributing hardly anything yet. And then it grades, but it would be 3 to 4 of those that are still cleaning up in some portion of it. The fourth closest 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 as we talk about lateral length is, can you actually clean up a well? And so 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 complete a clean-up. And so 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 drill the 9,000-foot lateral, could you ever even get it cleaned up, or if you have to drill 6,000, can you get it cleaned it up. So that's something we're learning right now. But 3 to 4 stages are still in some portion of clean-up stage.

Michael Schmitz - Ladenburg Thalmann & Co. Inc., Research Division

Great. And then just a follow-up. On the Fayetteville, did you say the -- 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 Fayettevile?

Steven L. Mueller

They could. I am not going to go say "expected," but it certainly looks like they could.

Operator

Our next question is coming from Robert Christensen of Buckingham Research Group.

Robert L. Christensen - The Buckingham Research Group Incorporated

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

Steven L. Mueller

We really don't have any data on that right now, to tell you the truth. We did not do microseismic on that second well. So it's really just indications from flowback. That's all it is right now. So as I've talked about in the past, when we frac-ed it, you've got some models that you use for pressures and things as you're frac-ing to see if it's growing the way you think it should grow. And when we frac-ed 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. And 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 fracs. So whatever we're doing, we're kind of pushing the limits, and we'll have to in some future wells to better understand that part, Bob.

Robert L. Christensen - The Buckingham Research Group Incorporated

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

Steven L. Mueller

Yes, we're isolating -- I don't know that we'll just do one when it's all done. We're doing one right now. But we've isolated some of the frac intervals that we had. And what we've done -- the closest one to the vertical part of the well was also in 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 fracs we've done to date. And we wanted to see 2 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 frac intervals. And I could see -- after we do that, depending on our results there, you might see us do something else in that first well in some other frac zones. But 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.

Robert L. Christensen - The Buckingham Research Group Incorporated

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?

Steven L. Mueller

It hinges on really 2 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 both from -- if we drill a well, say, offsetting this one and it's got a super low pressure, you're going to have to drill more wells to figure it out. If it ends up that there's some reason that you can come up with a wider side 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 are some differences that are much greater than we expect, and then we need to drill more wells to figure out those differences.

Robert L. Christensen - The Buckingham Research Group Incorporated

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 some points of encouragement at this juncture as a readership crowd. What could you offer, broadly speaking?

Steven L. Mueller

We're -- if you think about tests that are out there, there's 3 tests today. We've got 2 of them. You're seeing better production in each one of the tests, and 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're not necessarily bad things yet. You can find things that don't match the model and just say that 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'd find a window where you'd have the optimum production. It gives you encouragement that you can do some other things. So 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. It 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. So we continue to be very excited about it. And where we're at, at our 2 wells and Cabot's well in the play right now is ahead of where I thought we'd be, frankly. I thought we'd have more issues and we'd have more question marks. And we are going down a learning path. So it just comes back to -- that's the fun of exploration: Every well is a little bit different in how you fracture that in and what you can do next on it.

Operator

Our next question is coming from Joe Allman of JPMorgan.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

So 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'd be, but are not the production rates discouraging? And is there anything else that you're seeing that might be discouraging?

Steven L. Mueller

I'm not sure I’d say the production rates are discouraging. I -- you have to kind of think of 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. And the fact that we added lateral length in a second well and got better rates when we did that, and so we -- if nothing else, we can continue to add lateral length to at least part of this until some of these other things I've talked about keeps you from getting there. So I think that continues to have encouragement there. I don't necessarily think that 300 barrels a day is a discouragement at all. And 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. So we know we can sustain that rate for a while. Now it’s can we 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 higher pressure, certainly, a higher pressure could help lift fluids out, but it will cost more. So one of the things we have to do on this third well is figure out, is it helping with whatever is going on? And then, we’ve talked about in the past, we thought, in a play, we needed 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, it depends if there's an area that's pressured. It may be a little more cost that you have to have and you're going to have to have a little bit more rate. So it's not so much a discouragement, it's just we're going to have to learn. And this third well will tell us how much different it is than the first or second wells are.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

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

Steven L. Mueller

Well, I don't know. Maybe 20% higher, 10% higher. I don't know. 60 barrels a day. 30 barrels a day…

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Got you. And then just could you clarify the $50 million of more capital? Like, what are the differences between the original plan and the new plan that adds $50 million of more capital?

Steven L. Mueller

Well, without going into a lot of details, we're taking about $20 million out of the midstream, and most of that's in the Fayetteville portion of the 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. So it's 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. We'll probably go a little faster getting down to that 7 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. So 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. And 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'd want to accelerate a little bit. And then we'll make some decisions about Colorado. And really, right now, we have the 2 wells in Colorado, and depending on what we see, we'll have some more drilling after that that’s not really counter [ph] to anything that we're doing right now.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

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

Steven L. Mueller

Yes. Or we're assuming we will.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Got it. And that assumes bringing the second rig in. Is that right?

Steven L. Mueller

Yes.

Operator

Our next question is coming from Mike Kelly of Global Hunter Securities.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Following up, Steve, on your comments earlier that you're being diligent in terms of flowing these Brown Dense wells back, if somebody could give the choke size. And really, just kind of 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.

Steven L. Mueller

Yes, the -- we slowly opened the choke up. So we started 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 it -- we just -- we'll go, like, 4 or 5 days, 6 days, and we'll kick it up a little bit, 4 or 5 days kick it up and watch what happens with both your water and oil rates. I think, kind of your second part, help 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 of weeks. And the oil rate as a ratio compared to the water rate has continued incline. And I know some of our internal discussions have been, will this have a lot of formation water? At this point, we haven't seen formation water. So 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 and how much oil will be there and what that final water rate will be, if there's any water rate. And so that's all still working. But just the fact that the water dropped off hard here recently, oils in a ratio basis is going up, as far as ratio basis, says it’s 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 parts 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 the sustained rate you can have to get the target EUR that you have to have. And frankly, we just don't have enough information to be able to understand whether we can or can't do that yet. So we're just going to have to stay tuned, and we're all going to have to watch, and we’re going to probably need about 6 months production on 3 or 4 wells, not just a 1.5 months production on one well.

Michael Kelly - Global Hunter Securities, LLC, Research Division

And 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.

Steven L. Mueller

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 that big push is we've got the real big blocks. So if you want to go put a big push in the Brown Dense, you're going to have to kind of work at it hard. And 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're off doing Niobrara and they're not worrying about this play. So right now, both places -- it may be up $25 an acre or something, but it's nothing significant.

Operator

Our next question is coming from Jack Aydin of KeyBanc Capital Markets.

Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division

Steve, what -- how much of a decision -- impacted your decision, the oil kick in the third well? And did that also made your decision easier to permit the 4 wells that you're talking about? And how close they are to this third well?

Steven L. Mueller

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. And so the -- certainly, the wells we're permitting now were not under our 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?" And so you're starting to have to react to what you saw from a surprise, basically. Now how close they are? There are some fairly long step-outs. They're not all just -- as a matter of fact, they’re not right around this well. I think the nearest one to this is probably 8 to 9 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'll see in the next wells as we go through. So you'll kind of 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. So it just -- it evolves as you learn, and that's what's happening right now.

Operator

Our next question is coming from David Snow of Energy Equities.

David Snow

I'm just -- I had a couple of macro questions on shale. You made a point a few years back about compressing the learning curve and getting 2 years in Fayetteville versus, 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?

Steven L. Mueller

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. So if you think about Haynesville, well was deep and took time for each individual well. The industry could [ph] -- very quickly ramped up to, like, 180 rigs and basically could take that play from the first couple of wells, just learning about it, to producing 4 or 5 Bcf a day in 3.5, 4 years. So there's variables in there. And you kind of see those variables. When you look at the Utica play that they're working on, those first Utica wells that people were talking about already are on -- probably almost 2 years old, and you're just now starting to see that ramp up, and that has to do with just the play and the area and how fast the industry jumps on it. So I don't know if there's an answer to say how fast any average play would work. I will say that we're learning from each other. So the Fayetteville, what we did in the Fayetteville, when we first started doing Marcellus, we learned from that. What we did in the Marcellus, we learned from, and we’re using it in the Haynesville. What we use in all these other plays, we're learning and using in Brown Dense and in Colorado. So we expect that, because of what's been done in the past, we'll be able to get up this curve very quickly. 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...

David Snow

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

Steven L. Mueller

Yes. We came up with the idea almost 3 years ago now. We started leasing it about almost 2 years ago. And then we spud our first well in, I think it was, September, late September time frame last year. So from a drilling standpoint, we've only been working on it now 8 months, 9 months, somewhere in that range. And then as far as the risks 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 2 ideas a year over a 5-year period of time, have 10 ideas that we've tested, and 2 to 3 of those work. And part of success comes to the size also, not just the fact that it produces commercial quantities. And we said that, those 2 to 3, we want to be big enough to replace the Fayetteville Shale. And I think we're on that track. And when you take a look at Brown Dense and the Colorado, and then 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. So 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 talked about before, in the Brown Dense, I think we're getting closer, but we're certainly not to a point where we can say, yes, it's going to work here.

Operator

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

Steven L. Mueller

Thank you. I started the conversation today saying I thought 2012 will 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 you think about the Fayetteville Shale, we're drilling faster than we thought we were going to drill. We're adjusting to that. We've increased our vertical integration, and you'll start seeing the effects of that next year on the cost-cutting side. We've looked at and are drilling the best wells and can drill wells that work in this economic environment.

Marcellus, we continue to get the takeaway we need to ramp up. And if you think about last quarter, we talked about a maximum takeaway 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. And what could be more exciting than having a well at TD, in Colorado, getting ready to sidetrack it; having a third well in the Brown Dense and seeing differences but also seeing progression as you go through the whole process? So we're excited about the year. We're excited about the quarter.

And then 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 8 years. And it truly is a milestone to hit 2 Bcf a day gross production and 2 Tcf produced out at Fayetteville Shale. And who would've thought 7, 8 years ago that we'd be selling Overton and that we would have produced 2 Tcf out of a play no one even heard about? So I want to thank you for following us all this time. And 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. I'm looking for those milestones.

So thank you. And we’ll talk to you next quarter.

Operator

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

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