Steve Mueller - Chief Executive Officer
Bill Featherston - UBS Securities, Inc.
Southwestern Energy Co. (SWN) UBS Global Oil & Gas Conference September 20, 2013 8:30 AM ET
Bill Featherston - UBS Securities, Inc.
Okay. If I could ask everyone to get seated, we are going to get started with our first presentation this morning Southwestern Energy, which we have rated buy. It’s been an exciting growth story. Historically, a lot of that has come from the Fayetteville Shale and as we look forward with their increased position you will see a lot of that growth coming from the Marcellus.
Here to tell us about the story is Steve Mueller, CEO. Steve?
Thank you. And that’s probably one of the best introduction you could possibly have, that is my whole talk right there. So we’ve had great run in the Fayetteville Shale and I’ll talk about, a little bit more about that great run has been continuing to go in Fayetteville. And then, certainly, we’ve built the position in the Marcellus, [inaudible] position in Marcellus.
There are really, as we think about Southwestern Energy I want to remind everyone, yes, we are the number fifth largest gas producer in the Lower 48, but we are driven by some other objectives and those are the objectives we will see through the presentation today. But we want to stay focused. We want to use economies of scale. We do have vertical integration. I’ll talk about all of those as we go through. And we like to get in early in the plays and to put that position together and certainly, what we did in the Marcellus and in the Fayetteville show that.
I will have some forward-looking statements, as matter of fact. I’ll give you some hints of 2014. We haven’t done our budget yet. But certainly some of the things that we did at the end of the second quarter kind of can point to some of things that might happen in 2014 and what we are thinking about going forward.
As you think about our company and you think about what’s happened to our company. Today we get three sets of questions. One of the questions are, is how fast can you grow the Marcellus? How fast you want to grow the Marcellus? What’s holding you back from growing the Marcellus, it’s all in that kind of question?
The other question is the kind of questions [inaudible] today is what’s going on - the basis in Marcellus, or the basis affecting you in the Marcellus, I’ll talk a little bit about that.
And then the third question that we get is, what should we think about your exploration program and when we should expect something in the exploration program, and I will address all those.
What’s interesting, the question we are getting today have very little to do with the Fayetteville Shale and people obviously must think they’ve got Fayetteville Shale figured out. I will show in the presentation today that it’s not figured out yet and we are still working on it. We are still learning. We are still getting better at what we are doing and we got a couple of surprises left there as well.
Had a great second quarter. As a matter fact we set a record in the second quarter. I’ll show you in some of the slides on that. We did update our -- both our production, I want to guide a little bit higher on production for the year in the second quarter and we actually guided our capital up a little bit and I’ll talk about how that goes.
This just shows our historical growth in various areas that are out there. I talk all the time in the slide, one, two slides that send out the most demand here is that second on the left, where it looks at gas price, gas price last year, we all know was a tough year, was almost half what it was the year before.
But when you look at on the second graph on the right, you look at our EBITDA; we almost match the previous year on the EBITDA side of it. We really cut cost, grew production to hit that EBITDA and that set us up for this year.
This year average gas price is about half point between what it was in 2011, 2012. We set records in second quarter on the EBITDA and you will see us, I think for the year set records there. You will see us set records again on production as we grow over 12%, 13% that side of the equation.
And on the F&D side, last year certainly especially in the Fayetteville Shale, we went from having 1500 spuds on our book, so we are having around 300 at the end of the year. We will get a lot of those back this year and you see that F&D go back to what I think it will be a normal range for us just over $1 per Mcf.
By the way we do to that as we stay focused. This slide hasn’t changed in several years. From a capital standpoint, I am going to detail the next slide, but half the capital on drilling side is going to Fayetteville, half is going to Marcellus and then there is a little bit in our exploration area.
One of the key things about our exploration is that we spent the last two, three years to get our exploration where it is today. I get asked a lot of time, are you on schedule, we are right on schedule.
Where we want to be today was have over 1 million acres that we are looking at any point in time. What we want to do is test two to three plays at any given year and because some of the plays go over a year, have four projects working at any point in time. Today we have four plus projects working. We have 1.3 million acres. I’ll talk a little bit about that later in the presentation.
From a capital standpoint, we’ll invest $2.2 billion this year. As I said about half are going to Fayetteville Shale, $900 million, $870 million will go to Marcellus, about $160 million will go to the midstream part of our business and that’s almost spilt half and half between Marcellus and the Fayetteville Shale. So about $220 million, a little over $220 will go to the exploration part of our business.
And then, one of the things we announced at our second quarter earnings call was it, we had $50 million for new equipment and we didn’t say much about that at the call, everyone was asking about it and really I didn’t say any much about it was we’ve decided we have a leased buyback on the rigs we have which is an early buyout and we’ve decided to buy all the rigs that we own, okay.
To remind everyone we have 13 big rigs capable of drilling horizontal wells or drilling almost anywhere in United States. We will buy those rigs in this year. That will cost us about $50 million to do that. Some of those rigs will be sold between now and the end of the year. What we plan to do is replace those rigs that we sell with some better rigs using some of today’s technology, having a locking, having doubles, [inaudible] doubles and that have the ability to have AC power.
All that’s going to happen over the next 12 to 18 months and as that happens and we upgrade our rig fleet you are going to see where there is Marcellus we will be using or in the Fayetteville we are using more cost driven out of the equation, drilling faster and drilling the wells better as we go through.
This is the slide on the Marcellus and if you go back to first year, this slide had about 162,000 acres on it, today it’s got 300,000 acres. In the second quarter we closed an acquisition from Chesapeake for $93 million that was part of that capital increase we talked about. And also part of the capital increase was we had $50 million more that we put in the Chesapeake purchase to start doing some drilling [right] [ph] this year and build that drilling into next year. And so let me give you a real quick rundown of what we are doing and what we plan to do between now and end of the year.
We start about two years ago and in the middle of the map and what we call our Greenzweig area in Bradford County. Today we’ll show you another slide we’ve got well over 50 wells in that area. We are drilling pad drilling, all of the acreage is HBP and we are actually in the development mode there. It’s making about $300 million a day at the end of the second quarter.
Early last year, late 2011, we started doing initial drilling in the Susquehanna County areas and this is one of the big areas where that Chesapeake acquisition helped us. We had about 70,000 acres before the acquisition today we get about 133,000 acres in that county.
First production of any significant started in December of 2012, so about nine months ago. Today or at least at the end of second quarter we drilling over 200 million a day out of the Range area, what we call Range area in Susquehanna.
And what important is, as you look at that pipeline kind of goes through the middle of that map, that was the key to getting the production kicked off, it’s call the Bluestone line. We’ve been pulling that line towards the north, towards New York and by the end of the year we’ll have drilled all the way up to the New York border.
I can tell you right now we are about little over half way to the border with the drilling that we have and our results I am going to show in the next slide reflect the quality of the wells we are getting there, there are still very good quality in that direction.
Then as you swing to the south and swing down in Lackawanna and Wyoming Counties, a lot of that acreage is what we picked up in Chesapeake acquisition. You will see towards end of the year we’ll drill our first well then in Chesapeake acreage down in Wyoming County offsetting some wells there. Some of the best wells in the entire play have been drilled in Wyoming. We have got some offset acreage to that and we’ll drill the first one in that direction.
As you go south of Lackawanna County or Wyoming County, the geology changes very rapidly and the southern inner acreage you are not talking about 5 Bcf plus wells you are talking about 2 Bcf type wells.
So what we are doing next year, you see us drilling across Wyoming acreage, trying to figure out where that line drops off and where that production stays in the high end of the overall process.
Just moving over to the Sullivan County, moving back towards the west, Sullivan one has the least amount of infrastructure in the county. What we are going to be doing started in 2014 is drill four to five vertical wells. There are some vertical wells in the area but we need to get enough wells in there to figure out what kind of gathering system we need and then you will see us start talking about development.
So Sullivan County is really 2015 development scenario and say what do you think, why do you think there is any development to do in Sullivan County, just talk about the southern side of Wyoming. I mean lesser quality.
While just south of our acreage there is a field that has several wells, I don’t know, I think 15 wells, those wells average over 8 Bcf as total EURs. When you go north in the Bradshaw we already know from production there by our company and other companies that you are talking about 6 Bcf to 8 Bcf wells in that area. So we think Sullivan has good acreage from all the announcements we have. We just have to get that gathering system size going to that area.
When you move over to Lycoming, Lycoming first production, Lycoming was November this last year. We’ve got now well over 10 wells and by the end of year we’ll have close to 20 wells in Lycoming.
We are actually kind of comfortable of that with the acreage, we are drilling pad drilling on it and what’s interesting about Lycoming is that we only have two large leases with just a few other smaller leases and so just a little bit of drilling, and we already HBP in all that acreage we go there, so we go whatever pace we want.
And as you move north in the Tioga County, again right along that PVR, Penn Virginia line, we know that acreage is good, just north of is Shale Ultra and of course the south we got our acreage and you will see us drilling at least one well towards the end of this year and you will see a development program in 2014 in that acreage. So this is going to be very active for us as a company and in the next couple of slides, I will just show you little bit what we have done to date as we built our production.
This has two sets of data on it, one, little graph in the corner, that’s hard to read. I’ll talk little bit about how we’ve been able to drive cost out of the system, just like we have in the Fayetteville Shale. Today just over 11 days to drill well about 6.5 million to drill it.
The production graph, the darker line that you see, shorter line that has been the nine months of production that we have had in the Susquehanna County area and you can see we just over 40 wells. We are doing over 200 million a day and with 70 wells in the rest of the Bradford area, you can see we are doing about 300 million a day and its hard to see on here, but you’ve got the little bit of the few wells that we have in Lycoming and also on the chart.
It’s growing very quickly. If you’d match this chart up against any of our competitors, I don’t care from the southwest corner, the northeast corner to see this is a growth rate per well comparable to anyone else in the area, this shows that the northeast corner is good and its good beyond just little spot in Susquehanna County.
And this just show you little bit about how good that is. What we have done here is, we’ve broken wells out by number of frac stages, one of big debates and we are learning what the right answer on this in the Marcellus anyway.
One of the big debate is, how close you put the fracs together? How close you put the preparations together? So what we’ve done is tried to show you what that is. Most of this wells again on Bradshaw County we just had six to eight months of production in the Susquehanna block.
As you work your way through it, there is various lines on here, but the top one is greater than 18 stages of fracs, the next one down 15 to 18 and the very bottom one there is less than nine. So this just shows you the quality across those. The smooth lines go from 4 Bcf to the top line 16 Bcf.
And as you look out in the future, what we think we are going to average is somewhere close to 5,000 per laterals and we’ll space those frac spacing, we’ll have 240 to 250 feet apart and its a little bit different than the industry at least in Susquehanna is doing and I think in Susquehanna you might see a little bit closer than that we make it down close to 200 feet apart.
But as we swing over to Lycoming and Bradford, we have done enough testing. We know that’s going to be little wider there and maybe as much 300 feet apart. So I don’t say 240 foot average. The geology is not the same every where. The wells don’t perform exactly the same. But we think that will be the rough average that you see going forward with.
I might also mention, so we had $6.5 million average well today. As we look out in the future, certainly we can take two, three more days out of the drilling of those wells. But I think the other key things we look out in the future, is that, as we get all of the infrastructure built, nice infrastructure not just the gas infrastructure, I’ll talk about in the second, but as we get the water infrastructure built.
Here it’s moving water. You do it for most part underground in pipelines, we’ll have it completely build out in all of these areas except for that Sullivan and maybe some of that Southern Wyoming some time next year.
As that comes in you are going to see our cost of moving water go down and I’m very comfortable within the eight -- within next 18 to 25 months that $6.5 million well be a $5.5 million well. So there are a lot to drive out of that side of equation.
Now let just talk for a second about total production and what we’re doing on that side of the business. You know various companies have different ways of hedging and we hedge -- we hedge physical hedges, we have 232 Bcf hedge next year physical hedges at $4.44.
We also hedge in the sense of vertically integrated, as long as vertically integrated, the only cost that you have is just little bit of capital you have on whatever that vertical integration that years in salaries, so we keep that part of it.
It’s important I want to talk about the Fayetteville Shale in a minute. Our competitors are not drilling just because our vertical integration on our -- are -- has helped us keep our well cost $300,000 less there and we have been able to drill and lower prices than anyone able to do it. So that’s part of what we do.
The other part what we do is we buy firm capacity and if you think about historically, some companies and certainly, in the past in areas where you have plenty of capacity out there, you didn’t have to worry about that.
What you do is go to a middle man when you needed it, the middle man will sell it to you, usually there was more than one middle man are willing to sell, you can have real competition you get the best price for what you go down the road.
As we look at both the Fayetteville Shale and we look to the Marcellus, we realize we were in area that had not had significant production in the past and that there will be a period of time where it was very important to own firm capacity.
So what we started to do before we ever did our drilling we start building a firm curve. Today that firm curve goes from the 500 million we had it end of the second quarter to just under 900 million a day in early 2017 and when I say that, there’s actually a bump in 2015 we go. We’re about 900 million and drops down little bit and goes back up. But basically we’re above 800 million a day in 2015 and beyond, and part of what we done our capital budget is, design our capital budget to fall that curve up.
And with the acquisition of Chesapeake, we realize we need more firms and you will see between now and end of year they will add some more firm to the overall curve, but we will also think end up having to commit to some new, completely new pipe and I think that decision will come out before in the year. I get ask whole time, are you going to match that firm exactly, where you -- the firm is a hedge.
And so when you think about what we can take out of the basin right now, today we can take out over Bcf a day just in our gathering systems going and tightening the lines. Our concept behind the firm is two liquid points. So that as the system is developing, you have as few problems as possible and you go to as many liquid points as you can.
And part of that’s what we evidenced today, like I say the question to you is what’s going off with the basis and what’s going to happen with basis. We have been saying for the last year plus that we think ultimately Pennsylvania, all of Marcellus gets basically basis pushed down to rest of the country, which means it goes from today NYMEX flat to NYMEX minus 20 something cents. I don’t know if it’s $0.22, $0.24, $0.26 but somewhere in that range.
We have been running our economics there with quite a while. Now, to get to that point is going to be a very lumpy road and you’ve seen that. You’ve seen this week in [Lithy] where the [Lithy Hub] was lower than a dollar and then one day this week it was done in $0.30 range for what you’re doing. And that’s one of the reason, we think it’s important to have firm.
We’ve been able to at least right now to get around that problem and not have much issues. As a matter of fact, we have a little bit extra capacity. We bought some of the $0.30 gas, not much about $20 million a day for a couple of days, bought some $0.30 gas and sold for 330. So we actually made a little money on the deal.
I know you will say we can do that forever but I’m not going to say the [Lithy] is going to be the issue. I think over the next two to three years, you’re going to see various spots, various hubs have issues. They are going to -- it's not going to be as predictable. It’s just [Lithy] this line or that line. And we think it’s important that you have outlets to those various areas.
Certainly, as gas price continues to go up or as it goes up and as you get into winter where there is no issue with the hubs and they want all the gas you can possibly have. And at that point in time, you’ll see us sell more and we’ll sell as much as we can. So what we’re trying to do here is build a hedge portfolio with what we’re doing firm side and we’ll continue to do that up over a Bcf a day and right now we’re targeting some to 1.1 Bcf to 1.2 Bcf a day hopefully in the 2017 timeframe.
Let me jump quickly to Fayetteville Shale. I said we’ll get no questions about Fayetteville Shale. I’ll show you couple of slides, we continue to get the constant. I mentioned before, we’re doing $3000 less than our competitors. But what the industry thinks, it has happened with Fayetteville Shale, we’re improving the quality of the wells also and we’re expanding what people would call the core area.
And if you get that spot on the map right, we’re at Cleburne, Faulkner county kind of all intertwine would like. There is bunch of blue and blue and yellow stars. Those blue stars are $5 million a day or higher wells. Yellow on them is wells we drilled in the last 12 months. So it shows you where we’ve been drilling the better wells in the last 12 months.
That area we had almost no blue stars entered about a year and half ago. As a matter of fact in the first quarter, we had a lot of questions about why our IPs were down. I said, we’ve gone back into one area. We fracked some wells. They didn’t perform the way we wanted and we’ve got about 2.5 million a day wells versus the 3.5 that we were looking for.
Well, just as last week, we put a pad on production. We set our all-time record out of that area -- out of the entire play. We have a first 10 million a day well. That pad has five wells on it. Those wells all average over 5 million a day. First time, we’ve ever had a pad over 5 million a day. And last week, what’s going on, what’s changed, that’s all kinds of thing. It’s not a simple thing. There’s some good rock there. We won’t have a frac to walk better.
We’re doing -- we continue to change how we’re doing the fracs. We’ve learned across the fields the fracs, the way I did the frac isn’t the same. And we’re fine tuning that just like we talked about a few years, we would be in that stage now. And then one of the things we’ve learnt on the southern side of the Fayetteville Shale is that if you rest the wells like you did in Utica, like you did in Haynesville. And in our case, less than six months or three months, sometimes you don’t have to rest on a couple of days and certainly on average is between 10 and 20 days.
What happens is we get almost no water back on the flow back where you get significantly better rates and looks like it even affects our EURs. And I don’t know why that’s the case. But I can just tell you that we’re still learning the Fayetteville Shale and we still got a lot to learn. Just remind you that we’ve got 150,000 acres in the federal that we’ve just -- we drilled about, I think, 13 total wells on today. And you’ll see us start developing that in a couple of years once we get all those federal paper work done.
And in the upper Fayetteville, just like there is an upper Marcellus and upper Fayetteville, we have about 150,000 acres that has about 20 wells in it. We know its there. We know the quality of those wells. Because on the high side, we got 5 Bcf wells and low side 2 Bcf. They work. You will see us over time slowly develop that area but that’s a new development over the last two years also. So Fayetteville continues to grow and it’s the thing that makes us the fifth largest producer in the United States.
Just to share a little about the trends in Fayetteville. Just mention, we average about six days to drill well today, the best we ever drilled the well about three and quarter days. People ask me what’s the number.
Two years ago I said I didn’t think we get down to average six consistently. Now, I’m saying I think it’s little fives. We just have to keep working on in that direction. I think the key things at middle graph on the well cost. I think we are one of the few companies that can say consistently since 2007 through ups and downs through all kinds of various season going on, we’ve been able to drive our cost down.
Lowest quarter to date, $2.1 million per quarter, that’s first quarter this year. Average right now for the year is about $2.3 million. You will say where that’s going to go, especially with the fact we just put our own factories to work beginning this year. You’ve not seen the full effect of those factories.
I think this number in the near future is low 2.1 -- $2.0 million to $2.1 million per well. That helps as we think about what’s going on in the overall cost and what we’re going to do in the future. And I mentioned before little bit hence about 2014, we announced at the end of the second quarter, we’re actually going to drill a little more wells this in the Fayetteville than we had before.
We had earlier said about 330 wells. We’ll be close to 400 wells this year and people asked why did you do that. It’s really our call on what we think gas is going to be in the quality of wells in the Fayetteville. We’ve always said that if we had gas price in the high threes than we had 24,000, 6,000 wells drilled and it looks to us because we’re looking into 2014-2015, we’re in that world, we’re high threes, little fours at minimum.
And so we decide to do as well as operate in the middle of the year, go from eight down to seven, only drill 330 wells. We continue with eight rigs. We continue that into 2014. For those who have followed us, we’ve always talked about the Fayetteville Shale, over the last two to three years that we want to live within cash flow, investing $70 million more this year will let us grow the production slightly higher than we are going to do before.
It allow us to start attacking that 4,000 plus well count but what’s interesting about that is Fayetteville Shale, when it’s all done, capital, everything else including anything to do with people, we will give $100 million back to the company this year. And so we’re well within cash flow and $3.70 oil.
And then on the midstream side, we continue to grow midstream. I said we have 160 million in midstream total this year, about $80 million going into the Fayetteville Shale. I would guess that now it will be slightly less than next year and then in the Marcellus, we’ll invest $178 million this year. And if I had to guess next year at some point in the same range, happening in the Marcellus, we gather about 2.3 Bcf a day out of the Fayetteville. We’ll gather about 300 million a day in Marcellus.
On the exploration side, I’m not going to go in a lot of details here. Brown Dense is the one we’ve talked about most as I talked about these three or four programs that are going up that we have. We’re on our seventh and eight wells. At the time of the conference call, the eight well we were just fracking -- just fracked the first zone, had some initial rates at the bottom of this vertical well, had four more zones to go.
We’ve done all of those except the very top one to date. We’re flowing the first four back and then we’ll do the fifth one and should have information by the time we have conference call at the end of October. The seventh well is waiting on what we learnt from the eight well. We’ve done one sets of -- actually two stage of frac yet. It’s a horizontal well. I think when it’s all done we’ll have about nine stages total.
About the time of the conference call, we’ll see fracking some there. For drilling our ninth well, our ninth well is actually stepped out. It’s a step out to the west and little bit south of our third well. It’s not on this map. And we’ve got some geologic concepts we’re going to test there in addition to testing high frac and how you get the entire project to work.
And then on the tenth well, we’ll spud mainly after the ninth and now we’ll actually be back up on the Arkansas side and near our very first well we drilled. So we’ll continue to work here. If you will say when you’re going to figure this out, what’s going to happen as you get down the road.
Our strategy right now is we’re using what I call the George Mitchell strategy, taking 12 years to figure out the Barnett. We think this is something that’s going to get figured out. I just can’t tell you how fast. As you look at down the road, you’ll see us they have reduced capital in the future there compared to this past year, about past two years but you’ll continue to see us work at it. We continue to get better of the fracking and for those who followed us, the whole issue here is we got 440 interval that we have. We know we get frac across the whole interval at least not the way we want across the whole interval.
We think we can solve that problem and so we just keep chipping the way at it. Is it this year, next year or 10 years from now, I don’t know but you’ll see us working on this, you’ll hear some more about in the future.
We also got our second well in Colorado. I’ll remind you hear this is not Niobrara. This is deeper older section of (inaudible). Its more keen to the Granite, Washington, Oklahoma and Texas.
Our second well is a horizontal well. It’s about 1800 foot. At the time of the conference call, we were just fracking the first part of that well. We’ve done all the fracking of all stages across it and we should have about 45 days of production on it at the time of the next conference call. So we’ll update you there.
I would guess, it’s going to take at least two or three more wells here to figure this one out, one way or the other. So we’ll drill a little bit on the next year. By the end of next year, we should have this one figured out.
In addition to the Colorado, we have a play going on in Paradox Basin and we were drilling that well at the last conference call. That well is down. We have perforated that well. Across most of the intervals, we want to ask, we should have got a couple of more we have to do but we will talk a lot more about it in November when we get to that conference call.
And I would guess again here this is the two to three wells more to figure this play out. And so it’s probably next year before you would actually figure it out. And then as you look to 2014, we’re finishing up leasing on some areas that we haven’t thought about. You will see us drill at least one new play in 2014, possibly two.
And this really brings us to what’s going on from a cash flow and capital standpoint. Key things here is we’ll generate at 375 range about $1.9 billion. Again we’re investing about $2.2 billion. You will say what you’re doing for that gap. We have about $1.5 billion borrowing line that at the end of the year should have about $300 million of borrowing line. We actually had surplus going into this year. So it will be less than that gap before the end of the year.
Key note about this is $0.25 move in price is about $70 million of total cash flow. And as I said before we are hedged for the last part of this year about 50% hedged at $4.76 and I said next year 232 Bcf but we had to this year’s production about 30% hedge at $4.44.
And that’s really -- from the presentation standpoint, all of our areas are working. All areas are improving where we want to be and we are doing the things we want to do and you are seeing in our numbers. And we set records on the production side, set the records on the cash flow and EBITDA. And I think we’ll continue to do that through this year. And I fully expect next year we know that great years will go through it.
So with that, I’ll open it up for some questions.
Bill Featherston - UBS Securities, Inc.
Sure. If I could just remind everyone to wait for the microphone before asking a question. I’ll start off with the quick one, Steve. Just to be clear on basis in the Marcellus, when you sell your Marcellus production, you’re selling at the end of the pipeline or are some of the sales occurring within the basin and then given that the basis problems become so visible how challenging is it to get incremental capacity?
Yeah. When you own a firm, there is a lot of different ways you sell gas. You can sell at the well head and somebody has gathered the gas. And so you pay to gather and treat them and then you take it to a point on the pipeline and whatever the price is in the pipeline you get; the other way to do it is the way we do it. We own firms. So we actually own the right for certain period of time to put gas into that pipeline and we pay for it.
And if you have to -- you pay for it whether we put the gas in or not. So you’re never going to have as much firms you have total production. If you do, you have to pay extra for your overall firm. What that firm does, it allows you to go to various points. And so for instance, we’ve got a system we put in a Bluestone line, goes for Susquehanna County that takes us both north and south, it takes us to Millenium or we can go south to Tennessee Gas.
We own firm of both Millenium and Tennessee Gas. Tennessee Gas has three different points you can sell at. Millenium has two different points you can sell at. So we have our choice of going north or south usually and we can sell at any one of those five points and that’s kind of the way you get around the basis issue because it’s not all those five or typically you’re going to have problems with them. And so that’s kind of the answer there.
What we’re doing is just trying to get out away from that point of sales used at the well head or right at the pipeline. So now at any point in time, we are selling some pipe, are selling some gas in the interruptible day markets however you want to call that. And those are the wells we just put on production. And in those, we may have some [trashing] [ph] on firm but the price we’re getting forms a floating price wherever it’s going on that day.
We usually sell our -- I'd say between 90%, 95% of our gas on the monthly -- normal monthly prices closing at the month. So and that -- again that’s a company strategy, how and when you sell your gas also. Now as far as basis itself, we do hedge basis. Today we’re about 70% hedged on our Marcellus gas at a NYMEX minus, I think, it’s $0.06. And that decreases over the next six seven eight months. And I think six months from now is about 30%.
Basis hedges are -- you can’t put them on. There is not a long market on. So you can’t put them out two or three years, you put them out six to nine months. We’ll continue to hedge basis. And that goes into your second part of your question on getting capacity.
Certainly as markets have issues, the basis hedge is hard to get, at least hard to get a decent price. And so that will always -- you will always have to play that game and how much you have from basis and whether it’s Marcellus or Fayetteville that’s why we have marketing group and they do the best they can on that side of it.
And then as far as us buying firm, if you think about today, there is actually quite a bit of firm on north east corner that’s not been used because several companies backed off on their drilling programs. And so we’re able short term again to use that basis and we do buy that basis from various companies.
And if you ask all the time well how much you are paying for it. We usually pay what they were paying or maybe couple of cents less and that’s because they have to pay whether they have production or not. So it’s liability to them and they want to get that liability off their books. They only sell us for the most part three to six months out, maybe nine months out because they’re thinking in the future they may start drilling and then they want to use it those that firm capacity.
So we can get short term fairly easy the long term is the big pipe. And you’ve seen all the announcements, you’ve seen various pipes that they’re trying to be put in, you’ve seen various pipes that’s trying to expand and what they’re looking for is enough firm commitment to actually do those projects and those are the ones we’re talking about and there are several out there. And I don’t think identifying those and getting part of that is issue and just what price you’re going to get it at and when are they are going to have their capacity available to you.
Bill Featherston - UBS Securities, Inc.
Any question for Steve? I’ll ask one more.
Bill Featherston - UBS Securities, Inc.
The FT deals that you’re getting at like what’s the duration of them, are they one-year deals or do you have visibility of five plus years out?
There are various -- you know the -- of that $900 million data that I talked about, half of that is 10-plus years, a little over half. There is 40 some percent that has a five-year type term on it with some kind of option down the road, it maybe a three-year or five-year option where we can at our choosing extend it. And then there is the other 10% -- 9%, 10% that is these little pieces where it’s easy to filling in the hole that the big firm didn’t have and it’s nine months, six months type of things.
Or I mentioned in 2015, we’ve got actually -- our highest firm that we purchased is actually 2015. The reason for that was there is one big pipeline, Constitution Pipeline that is due to come operational early 2015. What we wanted to do was buy extra firm for a year period of time in case that was delayed anyway. And it’s on schedule now. I don’t know it’s going to be delayed, but we’ll have 150 million on that line and we want to make sure we’re covered.
We’re not completed covered but we’ve 110 million purchased for a 12-month period and that was specifically just in case the Constitution got delayed and so there is various reasons and various lengths we have on them. As you look down the road to the various projects, I think the shortest timeframe of any new project, you’d buy firm at is five years, most of what they’re asking for is 10 years type timeframe on it.
Hi. I just wondered if you could give status on that exploration work up in Canada, the…
In New Brunswick?
Yeah, New Brunswick.
In New Brunswick, we’re in year four of what was supposed to be a three-year exploration program. And we’ve given a three-year license on 2.5 million acres. Two years ago, we were trying to shoot some seismic. We got about half the seismic shot and there were several protestors. And one of the things, the polling in New Brunswick shows that a large majority of the people in New Brunswick wants you to drill.
When I say a large majority, it’s something greater than 70%. And most recent polls a year ago were about 84% on drilling. But there are protestors and some of those protestors come in from outside, some of them are from the province. They actually blocked us about two years ago. When they did that, the province gave us an extension, basically we have a two-year extension on our exploration license.
We went back this year, shot some more seismic, I want to shoot five total lines about I think it’s about 350 kilometers of data. We got three of those lines shot, two of them are in the same contentious area. We had a problem with last time and we’re not going to get those shot. We have enough data now to pick the locations for wells and we could given the fact that we should get some permit here soon we could potentially drill in 2014.
The real issue comes in if we got stopped shooting seismic which is real new relatively benign since we’re using for the most part vibrator trucks so that than you have the effect of that anytime, how -- which is going to be actually physically drilled you might get the permit and so we’re working with the province right now.
So I don’t know the answer to that part of the question. We’re planning as if we’re going to drill next year, but we could be delayed. The province has said if we do get in delays they’ll continue to extend our license we could tell them what we want to do is drill wells.
And the next question comes in how much you get invested and how much more do you have to invest. The exploration license when you did the exploration license, we did a work program that was a $50 million work program. We’ve invested to date about $30 million in that. When we get down to drilling, we’d have all the $50 million. But once you do the $50 million work program, then you get an eight-year development license in eight-year period of time we need to drill about 30 wells, the whole 2.5 million acres.
So the problem is working with it, just line extended and opening up as they run across problems. But right now, it’s kind of -- we’re like overseeing. We want to drill some wells but we’re seeing some protest and we’re trying to get around this protest.
Bill Featherston - UBS Securities, Inc.
I think there is a question over here.
Steve, back on the Marcellus, so when you look at -- it seems like there is -- I mean, a lot of guys fight for the capacity that you want to add in 2014. So I think I didn’t quite understand the answer as far as like how much more is that going to cost relative to what you have now and how do you, when you look out, if I look up next year and see $2 gas in Marcellus that is just four bucks. As the $2 gas for a period of time, how do you play that and how you impacted as far as like are you going to be stung by that over and above your 500, 600 you have contracted firm if you don’t find new?
And the second part of the question is this -- I guess discovery by the market fact or anything in at all to your decision to I guess just drill a few more wells in the Fayetteville, keep that industry going into next year?
Now the Fayetteville decision is complete independent of Marcellus. So Fayetteville is simply in $3.70 plus oil, you’ve got 4,000 wells and then in $4 oil, you get 6,000 wells. You are only drilling 400 a year. It doesn’t -- you’re just not getting your NAV back unless you drill faster. So that was the Fayetteville decision.
In 2014, we’re in pretty good shape. I don’t know if there is a big issue in 2014. At the end of 2014, we have almost 800 million a day as we’re going over to 2015 and there is a couple of little dips in there. So, yes, in the summer we may have a little bit more exposure than we have this year but we’re not even worried too much about 2014. What we’re really working on is drill long term 2015 and beyond as what we’re really working on. You might see us at $30 million or $40 million or $50 million in 2014 that’s not the real issue from our standpoint.
Now the other part of your question is what happens if all the Marcellus drops to a very low number and you picked $2, it drops to a very little number. If that happens, we’ll just make a decision on what we’re going to do. There is some point in there that we’re not going to sell gas. So we could shut in gas.
Today, why he has got a problem, as I said, I can’t tell you which line is going to have a problem. I can say we’re trying to get to a lot of different points and we can get to a lot of different points. We can get some like different points right now to northeast market. So near term, I think we can get around most of what’s out there, but we think its hard quarter. And I remind everyone this is a summer time phenomena.
What’s happening to you and what happened this last summer little bit faster I thought was going to happen, but you’re basically producing 9-plus Bcf a day some number estimate 10 Bcf a day right now in Marcellus. And the average -- yearly average is about 12.5 Bcf a day but the summer time you only need about 7 Bcf a day in the northeast. That’s what’s happen to you now, although you still need 7 Bcf a day next year northeast.
There will be higher number. So you know the problems will be bigger but that’s why we have the firm and that firm gets us to more points. So we should have a better handle at it. When it’s all done even if we have say three months that’s lower prices that somehow we couldn’t get around that or the industry couldn’t get around it. That’s three months sort of the year.
In the winter time, the northeast needs 20-pluf Bcf a day of capacity. So you know you can sell your gas in winter time and you’re going to get whatever the better prices are there. So compared to that part of the country, really the discussion needs to start on to what happens to the other parts of country because the Marcellus is favored if you think about what’s going to happen in the future on demand side of the equation, you’re going to see demand for the most part in near term be from new power plants.
So these new power plants are Mid-Atlantic in south. And then the two privileged areas for that are Marcellus and Fayetteville Shale. Those are the closest ones in those markets and so the rest of the country are ones who’re going to have basis problems as much as Marcellus. Now Marcellus has got individual lines but as that whole thing works out ultimately there’s still a privilege market. It’s just a matter of right now you can’t pull it back.
And I don’t want to answer one of the questions. There is all kinds of thoughts that -- because of these various things that’s going on today there is going to be some kind of high price for getting the gas to some point if you buy more firms. I am not saying that but there is enough competition out there on various lines that it is a little bit higher than the old Tennessee gas that lines have been in for 50 years. And so it’s always been an $0.18 range but we’re buying stuff in the $0.25 to $0.30 range.
We’ve got one set of firm where we bought one chunk that’s $0.30 and then we want to get to another point. And we had to buy another $0.20 and so if we want to get gas from one point to the other, you have to add and gather at $0.50 but actually on any given line we haven’t paid anything more than $0.30. We’re not talking about any lines more than $0.30.
When you talk about 2014 you said you are ramping to 800 and there might be a little dip in the summer. Is that relative to interruptible or something or is it something contract structure? Are you talking about the market dipping in the summer, I didn’t quite understand?
Well, if you’ve seen anyone who wants our firm curve in detail by quarter just needs to contact Brad Sylvester. Investor relation guys will give it to him. But if you’ve looked at our firm curve, our firm curve has got a dip. It flattens out in the summer time and it goes, ramps up in the third and fourth quarter.
So we’re trying to fill in the little hole there but on a relative basis rather than being right now the way you think about doing, just keeping the trajectory we’re doing on the production, relative basis where we’re 90% covered by -- 90-plus percent covered by firm today. It maybe 85% covered next summer.
Bill Featherston - UBS Securities, Inc.
We had a question on the other side of the room.
Can you just elaborate a little bit on the likely impact on the market with these LNG developments and as they start to ramp up, what impact on the domestic gas market may occur and at the same time if you can sort of discuss how that gas will be supplied to those facilities and whether Southwestern will participate in one form or another?
I am probably one of the most bearish people and I wish (inaudible) guy could just jump in down. The LNG markets are going to have a lot of demand and that LNG markets are going to save the day and we’re going to have high gas prices in the future. Every time we’re looking at the economics, I just don’t see the economics.
If you had $4 gas you put the $5 on it, it roughly takes you to get to Europe and you are averaging basically what Europe has. You get little bit of differential. And if you can get it to the Far East but as you get to the Far East right now the contracts that we’re talking about, everyone understands we’ve got a lot of gas in United States. I don’t know if anyone in the Far East who is offering contracts is indexed to oil.
So as I look at the pure economics of LNG, I think it’s a good hedge for those people who are moving gas around the world. I think it’s important that the government in U.S. have the ability to export LNG. And it does have a little bit it helps to link a little bit to world markets but from a back to the producer I don’t see it being a large effect on what we’re doing.
And frankly I just had a hard time the days market for LNG is about 30 Bcf a day on the water any point in time. And it projects that by 2020 that we’ll get to 50 Bcf a day. When you start talking about numbers of 6 to 12 Bcf a day that U.S. is going to have in 2020 depending on who you’re talking to about it. You’re talking about capturing 20-plus percent of the market and trying to capture 20% of any market in any business that short period of time, I just have a hard time there too because there are lot of people who have natural gas putting perspective everyday in the world 16 Bcf a day is flair.
So there is lot of places that have gases worth nothing that they can go into that market by 2020. So I am not sure that the market is going to let us get as much as we warrant to it. Now that doesn’t mean we’re not looking at it, not looking at how to participate. Right now, we’ve talked to probably 50 different groups that would like to somehow be in the LNG part of it or in the LNG part of it.
No one wants any gas before 2016. And at this point in time, no one wants any gas at a price that’s different than the forward curve in 2016. And forward curve is very flat right now in 2016 but neither of those doing much for us today in what we’re doing. So we’ll continue to talk. There are some creative things that might come out of it.
There are certainly the combinations in whether it’s the power plants or the LNG where someone buys into reserves as well and there are some kind of premium and something goes with that that might come out that’s what the industry do. And we’ll look at all of those as they come up with. But right now everyone knows that the United States has more gas than they need and they’re not really talking about those higher numbers to get out of the country.
In terms of Marcellus, what do you see out, maybe NGL, so I think the crack you are holding?
Yeah. I am probably not the one to want to ask on that one. We have completely dry gas. And so I haven’t followed that market enough to know certainly it’s in the same dynamic that the total midstream is and that you just don’t have enough capacity and because you don’t have enough capacity and especially in the ethane side, the ethane rejection you are having the blend to do some things and you don’t have enough pipelines to be able to do that. Over the next three years, that will get solved. But I don’t know enough about the details as to how things are going to solve on the cracker side, this is place we just don’t do it.
Bill Featherston - UBS Securities, Inc.
Are there any other questions for Steve? If not, please join me in thanking Southwestern.
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