Steve Mueller - President and Chief Executive Officer
Thomas Driscoll - Barclays Capital
Southwestern Energy Company (SWN) Barclays Capital CEO Energy-Power Conference September 12, 2013 8:25 AM ET
Thomas Driscoll - Barclays Capital
I feel very pleased to have as our second speaker today, the folks from Southwestern Energy. Steve Mueller became President and CEO in 2009. Steve runs with what I’m going to call the best gas company I cover and some people think I mean the term gas in a pejorative manner, but no, I don't really mean it that way. But there is challenge looking out in the best asset. I think Southwestern is in some of the best dry gas assets in the country.
With that let me let Steve talk about the company.
Thank you. What, I want to talk about is what I talk about every time when we come up in these discussions. It's kind of the way we do our work and the way we go about what we are doing. It started in the Fayetteville Shale with just having a little bit of an anomaly. And then that anomaly went to learning. That learning went to discovery. That discovery then went to innovation and then that added value plus and this is the year we said we are going to add some considerable value plus to our investors, and I think the whole presentation is just to give you an example of how we have gone through that cycle several times in several different ways, in different areas and have continued to grow our business and add significant value to our overall customer and customer base.
We will have some forward-looking statements. I will actually talk a little about 2014. I know we haven't given any kind of guidance in that direction. I'll certainly talk about what can happen, has happened in 2013, what's going to happen through the rest of 2013. I mentioned before value plus. To just remind everyone that we have a formula that we have out there that's what we want to do is take the right people and we worked hard to getting right people. We think we've got some right people I think that’s shown in some if projects that I’ll talk through today. What we want to do is right people do the right things and he mentioned we are in some of the best gas areas of our country probably some of the world in the case of Marcellus. Then what we want to do is wisely invest those with underlying assets and I am very proud of what we've done.
This next slide just shows what going on in the second quarter. What I want to do very quickly here is, at the end of every quarter we take a look at our peer group that we use for our proxy and one of our financial people who does that was a little bit surprised by what happened in second quarter for us and it's easy to say you had a record, but what does that mean compared to your peers, so he just wrote me a little note and what he said was, that from an operating cost standpoint we’re the lowest operating cost of our peer groups we’re in the 100 percentile with $2.34, lowest production taxes of any one in our group, lowest DD&A of any one in our group, lowest interest expense of any one in our group, third lowest G&A of any one of anyone in our group, fourth lowest production costs of any one in our group.
Then this becomes significant. 15% cash flow growth quarter-over-quarter that was 89 percentile in our group, third lowest debt-to-cap in our group. That was 89 percentile, so that goes back to [inaudible] investing cash flow I mentioned before. Then from a gas production standpoint, we grew 8% quarter-over-quarter, which puts us in 86 percentile.
Now, our peer group is a group of many companies. Over half of them are oil companies and we were able to continue to with the gas projects match up against the oil companies any way you want to measures as we go through there. This just shows that in a graphical format. We will produce somewhere just sort of 650 Bcf this year, which is about between 14%, 15% growth. We are doing that in the face of the gas price that's the second part of the slide you see there.
Last year, from 2011-2012, we went down almost half in the gas price and this year we are back up about halfway back to where we were in 2011. What's interesting about that, if you look at the second one from far right, the EBITDA graph, we are just missed setting the record EBITDA even though we had our gas price cut in half and we did that with those costs I just talked about and we did it with the growth in production that we had overall.
Then those middle two graphs talk a little bit about what we've done from our reserve standpoint, the middle graphs reserve standpoint, the far right hand graphs, the F&D we did have significant price related revisions last year. You will see a lot of those come back this year as gas prices start to come back.
One of the ways that we can do this is, we are very focused and we continue to be very focused. I said this probably a thousand times.
If you look at us 10 years from now, I can't say exactly which areas we will be in, but there's only going to be three, four, maybe five total. We are not going to be in all the basins in the world and we are not going to try to be everything to everyone. I think the economies of scale is important. We've build the economies of scale. We'll talk about that.
The other thing we do is, we’d vertically integrate and we added at the end of this last year our own frac crews to already said delivering in all of our own sand to have in our own rigs, and one of the things we talked about and I will mention it on the next slide, we had a little bit on equipment side on a capital budget this year and that goes back to some of the vertical integration we are also doing as we go through. The vertical integration, the focus helps us get to those numbers I talked about.
This slide show the capital budget we’ll have for this year about $2.2 billion to be invested. It's split between the Marcellus and Fayetteville almost even. Marcellus about $870 million, Fayetteville about $900 million and we’ll invest a little over $220 million in the New Ventures program, about $160 million in our Midstream. Then I said at a conference call at the end of the second quarter, we had $50 million in our corporate capital. I had a question about this and I said there was due to equipment and so didn't want to talk much about that.
Well, the reason I don't want to talk much about that is, on the rigs that we have we actually have a lease buyback on those rigs. We have an early buyout if we want on those rigs and want to exercise early buyouts, so put $50 million into the capital budget for that. I didn't want to talk about it at the time of the conference call, because I hadn't told the banks yet we were going to do that, we have since told the banks, anyway, the thing about that is, we think we've got about half of them sold and what we will do over the next 12 months is rebuild some rigs, built-for-purpose, so we can keep driving cost down as we go into future.
Now what will happen is, they will come in at $60 million in the capital budget this year over next six to seven months, we will probably get more than $50 million back coming down to income side, so they will basically balance out and then we will build some rigs going in the future on another lease buyback type program.
Here’s part of the value plus that we have done in some of the better areas that we are in, this is the Marcellus Shale. If you were to look at this map in the first quarter, we had about 176,000 acres. Today, we got 336,000 acres. We finished a $97 million acquisition in the second quarter. What that did for us alone in Susquehanna, anyone who follows the Marcellus knows Susquehanna will be a premier county in the entire play for dry gas, but [inaudible] from 76,000 to 133,000 acres and as I said that's going to take us up to 300,000 acres total; [it fell] [ph] in Wyoming for us, [inaudible] counties and then we are already drilling in Lycoming and Bradford and just started drilling in the Susquehanna blocks. And I said just started drilling in Susquehanna. This shows a little bit of what we have done.
We have taken the three counties that we drilled in and put them on this chart and showing you what's happened. The one that’s on the - goes to the farthest right that's been on the longest is Bradford. We've been working there about two years. You see in the two-year period of time, we have taken it from basically zero production to almost 300 million a day or just over 300 million a day. Then that dark like that's in middle about Susquehanna, we had a little bit of production last year in Susquehanna, but basically in 200 days, we have gone from 20 million a day to over 200 million a day. That was all in the first half of this year and we are continuing to grow that.
Our overall Marcellus production will go from basically 500 million a day at the end of the second quarter to within two years, you will see us up over 800 million a day and we have talked about the fact that ultimately this is something over Bcf a day and that'll net us in overall production [inaudible].
The other part of this and it's hard to read in this chart, but we continue to drive our days to drill down just like we've done in the Fayetteville Shale. We think part of the reason we've been able to go as fast as we have is because of the learnings we have in Fayetteville. We've done it before. We produced about 3% of the nation’s gas and we are the fifth largest producer in Lower 48 states, so we have had that experience as we go through and you will see us continue to grow, you’ll see those days to drill go down. I think we will get under 9 days to drill. This shows we are doing about 11, 11.5 today. I think overall, we can take another $1 million of that $6.5 million [inaudible] there is our average cost for the past quarter.
From the quality well standpoint, this is some of the best wells of any kind anywhere in the country. These are matching with a lot of the wells you have seen in offshore and we've given some of the quality of the wells here, the various lines that you see, the smooth lines on there go from 4 Bcf in increments up to 16 Bcf. The jagged lines are showing what happened and depend how many times you frac the well and the lateral lengths in the well, a very top line on there is something above 17 fracs as you go through the overall process and you can see that all of these wells are running somewhere above 10 Bcf and we have got certain wells above 15 Bcf, 16 Bcf as we go through.
You may ask. That looks like an unusual curve. You are used to seeing a curve that starts and just drops off. These wells are so prolific that in the first six months in all the wells, we have not put them on compression. We've flowed them directly into to the main lines, those main lines are 1,100 to 1,200 pounds and then when we put them on compression, you get a bump in production and if you look at that top line about a year out you can see the jump in production, you had in production and so that's when we finally put them on compression, so why don’t you put them on compression to begin with, because you have to use gas to put them on compression and when you run the economics, we think is it more economic to produce them until the need for the compression and sell that gas rather than use the gas to run the compressors.
I would now like to jump to Fayetteville Shale. Fayetteville Shale is giving us new surprises and there's new things happening on these as well. This shows all the dots entire industry in Fayetteville Shale, all the wells drilled. It is over 3,000 dots on this map. When it's done, it will have about three times new dots as you overall. There's various scales on here, the great background, less than 3 million a day, the reds are greater than three. Then it goes to the blue star greater than five and then it's greater than six and the star with the yellow on them.
I said some new things are happening. We continue to drive cost down as we go. We've got our cost to about 2.3 million a day average for the first half of the year. In first quarter, about $2.1 million a day. That's from about $2.7 million. That's from about $2.7 million just a year ago in the overall cost, so we will continue to drive the cost down. On the day to drill, I'll show you slide in a second, but our days to drill is about six days to drill a well. Then from a quality of the well, we continue to learn how to do the wells better and we will talk more about on our quarterly call that we set an all time record for well just last week. You will a report from us saying we had a 10 million a day well, first one ever in the Fayetteville Shale. If that well goes on, that will be highest we've ever had for a pad on Fayetteville Shale. That will be well over 5 million a day for an average on that pad.
You say where is that? It's almost we don't map those counties stuck in through those blue stars. That area had almost no blue starts in it about a year ago and we are continuing to develop in areas as we expand outside of what normal people would call the core of the field. Again, we have got 3,000 drill, our company alone has over 6,000 drillings to display.
Just to show you some of the efficiencies that we've done. Sometimes we begin with and the whole idea here is to drive the innovation. You need to certainly see that. Far left is day to drill. As we said, we are doing about six days to drill a well today. Lateral length continues to go up. We are about 5,000 per lateral length average is. The well cost, any industry or anyone in our industry has been able to drive the well cost consistently down from 2007 for the day through all the various cycles that's out there from our both the service company challenges and then from what's happened in the economy. Then you can see on the last couple of slides how that's affect the production and then we look certainly forward to the cost last year. Our reserves were down a little bit and they are coming back in 2013.
We've also got a pretty large Midstream. I get asked all the time what are you going to do with the Midstream and how should we think about the midstream and really the Midstream is just to us part of that vertical integration. To take that part of that vertical integration that's going to take a significant value and as we see it now, we haven't seen that significant value to take that out of the system, but we continue to look at that as we go through just like we look at any other vertical integration as it makes more sense not to be vertically integrated when we will do it, but so far the economies of scale, every time we vertically integrate we drive our costs down and we add more to the value to the project and we would have not in there.
From a capital standpoint, I said earlier about $160 million total is going to be Midstream, about $80 million is going into the Fayetteville Shale. It continues to decrease most of that EBITDA you see on the slide is coming from Fayetteville Shale. From a standpoint of the Marcellus, roughly $80 million is going into Marcellus, and of our Midstream component, even though we don't have slide in here, we are gathering almost 300 million a day in the Marcellus. We are looking to starting to build that for that position as well.
Then we have an exploration program or option value that we have out there, all the stuff that's going on. We have over 1.3 million acres. I want to spend a lot of time talking in details about the various projects that we have, but what we started about a little two years ago is when we want to get to a point where we are between 1.2 million acres to 1.5 million acres on an ongoing basis, but we want to be testing three or four plays a year and we wanted to roll that through, so on a five-year period of time, we tested 10 plays. We thought there were about 20% to 25%, the success ratios is we are looking for and we would expect that we have two, maybe three discoveries in that five-year period of time, but we are up to 1.3 million acres starting to begin in 2013, we are testing four plays right now. We are adding acreage in other plays we haven't talked about yet, and I have got a couple of slides and some of the ones that we have done to-date, but we have talked about publicly Paradox Basin, where we have drilled a well and are just in the stages of completing that well. We'll talk more about in our conference call.
We have drilled in Montana, in Bakken of Montana. We were disappointed with those results. I don't think there's much to do else in Montana side. Then we have the Brown Dense in Colorado, which have two sites. Brown Dense is one of the first plays that we rolled out about a-year-and-a-half ago, a little year-and-a-half ago. Actually a little close to two years ago. We drilled right now about eight wells in the play.
We are currently drilling the ninth well. At the time of the call, we were completing eight well. It's a vertical well and we are just in the early stages of completion. It's a vertical well. It's about a 400-foot interval and we had five fracs stages. We wanted to put into well. We did the fracs a little bit differently each stage, so we wanted to frac it sought back, frac it sought back. We have done that. We've done it on four of the five stages. The fifth stage has been a couple of weeks, so by the time we get to the conference call, we will talk about the results there.
On the seventh well, that's a horizontal well. We've done one stage frac, we've put it back and you will see us fracking more. We'll talk about the time of the conference call in late October. Then, as I said we are drilling our ninth well. That ninth well is up nearly more between Arkansas and Louisiana and is one of those stars that has a little yellow star blue around the outside of it. Now, our 10th well, we will move that from the ninth well, nearly to the 10th well, both of these will be vertical. We'll actually move back into Arkansas and drill near that first well we drilled.
We are seeing some differences across the entire play, so those are [deposits] over the last couple of years and now we've got into a high pressure window as we get into Louisiana side of the play and there has been two things that had happen of significance besides getting the higher pressure window. There is one economic one of the plays drilled by a private company. It's up on the right-hand side of the map near our eighth well. Then we drilled the well, our third well, that while it won't make our economic hurdles, we will payout a well that is over $13 million well, so we've got one things, we know we got to one that's economic and we are continuing to drill out here. I get asked all the time working out for two years. Isn't it time to give up? We continue to get closer to it, so you are not going to see us give up on this one.
In Colorado, we built two wells in Colorado, put together about 300,000 million acres. This is actually for a little bit deeper section of the Niobrara. This section is in the north, just what they have done, they didn't have that section in their part of the overall area and everything they on the map. We are looking at is Pennsylvania intersection, but tie more to the Grant Wash, in Oklahoma and Texas, we've built two wells, the industry has drilled over 100 wells in Colorado in this play.
There's probably, I think, 15 already economic, so the game here isn't finding the economic well. The game is finding if your area is economic or not and we will have to drill two or three more wells to figure that out. The second well, we had finished drilling early in the year. We were fracking it at the time of conference call. We've done all the frac on that. We are flowing it back and we should have a good test for you talk about here in a month or so.
This just shows you are financials. As I say, we are going to invest $2.2 billion this year. It looks like the gas price is going to end up somewhere in the 370s to 375 range, so kind of middle of that chart. We will have cash flow somewhere around $1.8 billion to $1.9 billion. Our borrowing base is $1.5 billion borrowing base, so we had about $200 million to follow that beginning of the year.
You see our debt ratio. From a hedging standpoint, I talked before, we think our Midstream is a hedging type asset. We all of our vertical integrations helps hedges, helps hedge the cost. It also helps hedge some of the production characteristics, but we also physically hedged.
In 2014, we got about 232 Bcf, 233 Bcf hedged at about $4.40 and for the second half of this year, we've got about half our production hedged at $4.70, so we've got strong hedges in place. The first half of this year, our hedge is, maybe it's about $0.41 on what we are doing.
The key to that part of the story is, as you look at in the future, we have got a bright future from a gas price standpoint, because we have a new hedge, we do (Inaudible). We've got a strong balance sheet. We continue adding value as we through the equation and we are developing some great projects this year and it all comes back to that where I started with last point that we have here.
You have to have the curiosity to see the anomaly. If we see the anomaly, you can lead that into the discovery, we can lead that into the value plus. We have been doing that, we are doing it consistently. We are able to do it in high price and low gas price, we've been able to do it being a gas company and oil company and I don't know if we will continue to be a gas company or oil company as we go through the process down the road, but I can guarantee we can deliver as we go through the road and I think that's a key message today. We are developing value that a lot of our competitors can't no matter what part or climate we are in and we will continue doing that.
With that, I think we got a few minutes for some for some discussion?
Thomas Driscoll - Barclays Capital
We should do. Questions please? Maybe I am going to ask the first one. As you start to look into the 2014 budget, I know we're a little bit early. You know what the curve is, would you expect CapEx to move very much in this year's number?
Probably not a whole lot from this year, when we did our second quarter call, we revised our CapEx a little bit and that was in anticipation of where we thought the gas price is going to be. We are in the $4 world 2014, we think there is upward pressure on gas price today not downward. I still believe that. You will see a lot of gyrations over the various weeks in various [industries][ph] out there, but at the end of the second quarter as we are looking into 2014, we are going to look out six months. We are making decisions today of early about 2014 already.
In the Fayetteville Shale, we said we want to live within our cash flow as we are looking. Cash flow in the Fayetteville Shale was up over what we expected. We built our budget this year on $3.50. We are ahead of that. As we looked at it, we can continue drilling a little fast in the Fayetteville Shale and continue that into next year and we decided to do it, so we added about $70 million to Fayetteville Shale project, where we went from about 320 to 400 wells, roughly 400 wells drilled and that will grow our productions in low single digits as we are going through there and that was on expectation. We just keep those rigs running into 2014. The interesting thing about that was while we added some capital to Fayetteville Shale, it's going to deliver in 2013, if the price stays around $3.70, it’ll deliver about $100 million of excess cash flow to us in 2013, so we have already made some decisions in that direction.
From the Marcellus standpoint, we continue to build firm capacity, but we have a curve that will take us towards the end of 2015, almost 800 million a day. That's a four-rig program. We are running those four-rig program right now and we built into it a little bit of learning, so it will take roughly 100 wells this year to about 120 wells. But I don't think [inaudible] add another rig there. With those two, that's about $1.6 billion to $1.7 billion just doing those two things. Unless we have a significant discovery in the new ventures and we want to ramp up that discovery, we are in the same kind of ship where…
Thomas Driscoll - Barclays Capital
Yes. I missed the number. You said 800 million a day in the Marcellus by…?
Thomas Driscoll - Barclays Capital
I think, if you look at our firm, we'll get about 770 million in first quarter 2015.
Hi, Steve. Would you talk about what you did differently on the large well in the Fayetteville Shale? Whether you are moving recovery rates or you just [inaudible] more recourse in place and how replicable that is?
Yes. There's probably two major things we did differently. It's a little bit longer laterals but it’s [6,000 per] [ph] lateral and a 10 million new well. That pad though average about 5,000 collaterals. We continue to tweak the fluids and sand and like most plays sands fairly cheaper, [inaudible] very cheap, so almost every player out there in unconventional were adding more sand. We actually added about 20% more sand in our fracs and we have a little bit less fluids. We have been trying to figure out ways to keep that fluid down.
That’s one of your biggest cost. I don't think it was a fluid [side so much will be] [ph] very much. I think there was a little bit more sand, but the other thing that we did, if you think about some of the plays out there that - and they have all kinds of names for it, they rest the wells, they do something to the wells where they wait for some period of time before they put the wells on production. But we have found in only certainly parts of the Fayetteville Shale, it doesn't happen across the field, that we can monitor surface, the pacing pressure and we can actually watch or hear the water fall out of the backside as frac’ed it and we can pin it down within a few days of when we can turn the well back on, have the least amount of water in the well, and in this one area we found that it as we are watching that process, if we shut the well for anywhere between 4 and 10 days, again, the well tells us what that is, after we frac the well number one, there will almost no water back which helps on the cost side, but the well seems to be much better, that’s what we’re doing. We are trying to figure out why it seems much better, but there's a large area across the southern part of the field that the industry had written off even two years ago has been 2 Bcf territory. That isn't going to be 2 Bcf territory if you go out in the future, so it's not across the entire play [inaudible].
You mentioned that you are closer on Brown Dense and you are not giving up. What have you learned like this most recent well or the competitors' well that makes you feel so confident based up on what we have done so far?
Yes. It's what having to have what has happened. If you think about most exploration plays, we first get the play, be very excited about it and then as you get more and more data, the good ones will continue to be excited about. I mean, I should start usually you start giving some significant bad news and the plays goes the wrong direction. We haven't got significant bad news. One of the big issues that we've had in the Brown Dense is being able to frac across entire intervals about 400 foot interval. That's one of the reasons we are testing some verticals now, testing fracs it's a little bit cheaper to test the fracs in that direction, but I don't know where this is going to end up whether it's going to be a vertical or horizontal play just because it's such a thick interval as we go through.
Well, with each well, we are going a little bit farther out the fracs, we are getting a little bit more consistent with fracs, we learn a little bit more about the fracs, so that we think is solvable as we go through. One of the other things we had to do is, think about driving cost down and first of all it's had a lot of science in them. We are in our 9th and 10th well. These, 8th, 9th and 10th, had gradual science with them and when you see those costs going down that side of the equation, so with your cost going down you get a little bit fracs and you want to be in other direction and then we have this well as I said that industry partner, a private company has drilled. You will hope that you could duplicate that well. Unfortunately, no one knows exactly why it's producing will exist, but it does. It is going to be a commercial well.
They drill the well, we are going to do a horizontal. As they are doing horizontal at high pressure almost lost the well, could not back to do any of the horizontal work, but they had about 200 feet of open hole inside of the Brown Dense and we just put the well in production, didn't frac it, didn't put casing across, we didn't do anything. Came on in January for 500 barrels a day it soon was about 550 barrels a day was about 2 million days gas. It's going to be about 300,000 barrel well and it's a vertical well only have the zone open. There obviously a natural fracture or natural fracture system there, but it does tell you that the [produce] and we are getting bettered our fractures, so that's what makes me frankly which is going after as we go through. Now, next the question is, where are you going to throw it out? Why [possibly], but I can't tell you what else we (Inaudible).
Any other question?
Thomas Driscoll - Barclays Capital
Any other questions out there? Thank you very much, Steve. Steve is going to be available in the other hall, Riverside Ballroom. Thank you very much.
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