Southwestern Energy Company (NYSE:SWN) Capital One Southcoast December Energy Conference Call December 11, 2013 12:00 PM ET
Jeff Sherrick - Senior Vice President, Corporate Development
Alright. Next on the list would be Southwestern Energy. And I believe Jeff Sherrick is going to come up and lead the presentation. Come on up, Jeff. And Jeff is joined by Brad Sylvester and Matt Sicinski. Jeff is a Senior VP, Corporate Development. And Jeff, I will hand it over to you to go in and tell us a little bit more about Southwestern.
I just start out. I guess I will make a couple. We are going to be talking a little bit about the year end results and then 2014 guidance. So I will be making some forward-looking statements. And this document here talks a little bit about that.
Turning to the company, I guess I would like to start out with a slide and it gives you a pretty good perspective I think for Southwestern Energy. We are largely a gas company. 99% of our production today is natural gas and the slide that you see here before you is really kind of the progression of what the company has been able to do since 2008 and we started out to be about the 20th largest natural gas producer. If you look in the third quarter of 2013, the last yellow bar to the left hand side of the graph, you can see at this point in time, we are pushing really right about 1.9 Bcf a day of net gas production, which puts us right there at that number four, number five spot. We will be talking a little bit about what’s going to happen in 2014 and I can tell you now that we will be growing our natural gas production to the tune of about 200 million to 300 million cubic feet a day over the course of the year. So we will be over 2 Bcf next year. So we will be pushing very hard on that number as far as natural gas producing below 48.
If you look on the inset the little box in the right hand side, you can see a series of numbers or metrics there associated with the company, the first of which are reserves in production, this is associated with 2012. So it’s pretty stalemate at this point in time. I will tell you that when we look at the reserves in 2012, this is associated with the $2.76 average cost from an SEC reporting process during that period of time, which resulted in some fee, proven undeveloped reserves being written off our books.
As we look at 2013, we are currently going through that process today. We will be reporting that information to you in February after we complete the year end analysis. I will say that we are having a great year on reserves and I think you will see that number change substantially as you look at 2013 numbers. The production here of 565 was in 2012. If you look at our guidance or where we are heading in 2013 is about another 100 Bcf of production for the year. And as we look at 2014, we are moving that number again up by about 100 Bcf in the 750 some Bcf a day range. As far as the capital, it’s going to be very similar in 2014 as far as the amount of capital that’s going to our drilling operations. We will talk more about that in a minute. In the last little set of information here is really about the metrics, you can see we have had tremendous growth over the last few years.
Third quarter was a great quarter for us, where production was up 19%. And in particular, it was a record quarter on EBITDA. We have $526 million of EBITDA in third quarter. We expect fourth quarter to be another record quarter for us. So 2013 is firming up to be just a record year for Southwestern across the whole company. We are active in a number of new ventures. We are going to talk just very briefly since our time is limited today about one of those that will be the Brown Dense activities that are currently in progress. Strong balance sheet, we have got a lot of dry powder for things that we want to do. And if you look here when you look at the company, we have set the stage for very strong 2014. The capital is going to be roughly $2.3 billion, which is in line with what we are investing in 2013 are the $2.25 billion in ‘13 and production growth in 2013 were up about 16% in 2014 will be about 14% production growth for the year.
The graphs that you or the bars that you see in front of you here give you a very good perspective on Southwestern Energy over a very long period of time from 2002 through 2012. So again, it’s good historical trend. So data again is getting a little bit old. So I won’t go through the information here. I do want to point out two things though. If you look at the tremendous growth in the red bars on the very left hand side of graph, you can see how the tremendous growth in production has occurred. And again, we are moving that up by about 100 Bcf a year both in ‘13 and in ‘14 for a projection for the company.
The real winning thing here and we start to think of the whole market, Southwestern Energy is really managing our cost structure. If you look at the purple bars and you can see what’s happened to gas prices over that same period of time, we lost well over 50% of our gas price from mid 2007 through 2012 and then even into 2013 we think will average about 3.62 for 2013, but during that period of time, you have been able to see what we have been able to do from a standpoint of our earnings before interest taxes and DD&A. We have been able to grow that substantially. And again as I mentioned earlier on one previous slide, we are going to have a record year for earnings, EBITDA for 2013, so just great performance by the overall organization.
I won’t go into a lot of data here, but I will tell you that we are a very simple company in many ways and that we are located just in the few areas, but by having these areas of concentration, it’s allowed us to do really one thing and one thing significantly well and that’s to have vertical integration into our programs. Vertical integrations made a huge difference again for that low cost structure and the success that we have seen as a company as we have gone through the last several years. As we think about the future with the company, I will mention to you that the goal that we have is not to have ourselves in 10 or 12 basins, but to have ourselves in probably 3 or 4 or maybe 5 basins, but to have significant position, so we can bring that economies of scale toward.
From a capital investment perspective, which is shown here before you, this is again shown is a historical perspective over the last several years. If you look at 2013, you can see the $2.25 billion that we have planned to invest and largely has been invested at this point in time. You can see how that breaks out among the various components of our business. And if you think about it in 2013, we have two major programs in place both the Marcellus and the Fayetteville. And in years past, you would see the Fayetteville being the dominant investment. What you are seeing today and again the growth that’s coming out of the company is largely out of the Marcellus. You are seeing the Marcellus being roughly in 2013 about 50:50 when you include both midstream investments and the acquisition works that we did in 2013 in the Marcellus both being in the mid $900 million. Now, in 2014, what we are planning to do is we will be investing about $900 million in the Fayetteville and roughly about $760 million to $800 million in the Marcellus, the difference here being largely associated with the fact that we have the acquisition in the Marcellus in 2013. So very similar program than what we have – to what we have had in 2013.
Let me jump real quickly with the few minutes I have got left here and talk about the Marcellus, the Fayetteville and then the Brown Dense and then we will sum it up with talking a little bit about 2014 guidance. The slide you have in front of you here shows our position in Northeast Pennsylvania as well as some of the major pipelines associated with off-take for the production and the growth that we are seeing out of the Marcellus throughout Pennsylvania and the northern West Virginia. In our particular case here in Northeast PA, we have approximately 337,000 acres today. Our legacy position prior to the acquisition was roughly about 160,000 acres. We have added another 160,000 some acres associated with the acquisition earlier this year. We show three or four main areas of operations and I will start sort of toward the center of the page versus Bradford County. This area is called Greenzweig for us. It’s one of the landowners out there. It’s where we started our activities. We have drilled a number of wells there today. We produced over 300 million cubic feet a day. That gas can go both north and south on Stagecoach either into Tennessee or into the Millennium line.
In early 2013, we started developing the Range Trust, which is in Central and Northeastern Susquehanna Counties. We have been active in this area all year. We got our infrastructure in place in the first quarter of 2013. So we effectively have taken that area from zero to north of 250 million cubic feet a day coming out of the Range Trust area in 2013. So the south you see a little star there called price. This is an area that we developed at the latter part of 2012. We have drilled a handful of wells there. We produced somewhere in the neighborhood of about 30 million, 40 million a day of the price region today. All the way over on the bottom left hand side of your graph is Lycoming. We have drilled a number of wells about 10, 15 wells on one lease on the western side we are producing about 40 million, 50 million cubic feet of gas a day over there in the Lycoming area. The balance of that acreage, which you see in the Southern tier, is the acreage that we picked up from our acquisition in the second quarter of 2013.
The wells have been performing extremely well out here. Most recently, you’ve heard us talk about a well in the Range Trust area that came on at $32 million a day. Just to put that in perspective that well is roughly just to the very southwest of the store that says Range Trust, just to put that from a geographical position, where that’s located. The really impressive thing about this well is produced with roughly about 15%, 20% drawdown. Very strong well in that part of the field which again ties very closely to some of the performance that we are seeing over Greenzweig, which I think it starts to tie these areas together from the standpoint of what you might expect as the future goes as we go forward in the future.
When you think about our position out here today, we have 337,000 acres. We today have probably de-risked somewhere in the neighborhood of 130,000 to roughly 150,000 to 160,000 acres. Out of that 130,000 to 150,000 acres, we have done a number of tests and we feel very comfortable that we need to be on about 100 acre well spacing. So what that would represent is we have somewhere between 1,300 and 1,500 wells that we have de-risked today that sit within our criteria at least that we drilled a 3, 3.50 gas or better. If you think about it, we are producing today well over 600 million cubic feet a day out of roughly about a 150 wellbores. So we have drilled up about 10% of our de-risk inventory and we are about 600 million plus a day and we will exit the year probably a fair number above that.
Now, in addition to our activities that we have been doing as far as development on the horizontal program here in the Marcellus only in the lower Marcellus I might add. We have grown to step out and drill eight extension wells to start to test some of the acreage to the south that we have bought in the acquisition. The first well is going to be in Sullivan County. Don’t know if I can point with this, because we can’t, but anyway it’s in the very kind of northern part of Sullivan County. That’s going to be our first well. We spud that well. It will be a vertical well. We start to test the section. My expectation is as we go through this eight-well test program in 2014 to start to set this up for activities in 2015, you could expect another 40,000 acres to 60,000 acres will be proven up, which again I don’t know 100-acre spacing from their 400 to 600 wells to our inventory that point in time.
This is a graph that very quickly gives you a feel for how we have developed our position out there. If we look at on the graph here and we start with the big graph first and look at the purple lines. On the left hand side, this is daily rate million cubic feet per day. Across the X-axis these are days online, so you can see our production going to be in online a little over three years. So we are fairly early in the program here. And a lot of this was dictated by infrastructure or the lack of infrastructure when we first started out.
What I would like to draw your attention too is if you look at the green line this is the Greenzweig area, so you can see how we developed this over time. And I will tell you early on today Greenzweig is totally on compression, but early on and really until last year most of these wells were flowing against line pressures of 1,100 to 1,200 pounds per square inch, just to give you a feel for how impressive they are. We started developing the range area and you can see the 61 wells on the purple lines associated with range. You can see very quickly how that 250 million a day has jumped into the program just in this year.
The little inset box that you have on this graph, there is a lot of information it’s very hard to read. And what I will tell you is when you look at those 30 day rates, which we have allowed – we have given you to look at, they really don’t tell you a whole lot they just kind of (mender) around the 6 million, 7 million a day. The reason for that is we are not really flowing – we are flowing these against basically line pressure and most of these have not been put in compression. And we hold these wells back most of these are choked back substantially, so that 30-day IP rate doesn’t tell you a whole lot about the performance of these wells. What’s really important on this little inset graph though, if you take a look at this data is you can see the real benefit of the learning curve.
When we first started out here, we are drilling these wells in about 20 days, 22 days. Today, after only 150 wells, so a very small part of our work you can see the transfer of knowledge it’s come out of Fayetteville activities. We are now down to 50% of that by the 11-day rate. You might say well that doesn’t look like it’s been translated over into the well cost, which is shown in the very last column on that little inset box. You can see that we are down in that neighborhood of high 6s, low 7s, while part of that is due to the fact that we are still out here HBP and acreage, so we are putting one well per pad. Some of the pads are a little more expensive. And the other thing that we have done in the last year like a lot of other operators, we have learned that there is some real benefit here by reducing our stage spacing. So where before we had on average about 12 stages per well. We are now in the area of about 18 stages per well.
Just to give you a little more color as far as the performance of these wells, this graph here, which again on the left hand side is daily rate, million cubic feet per day, again versus days on the X-axis. And we have broken this data up amongst the various wells with different stage spacing. The very lowest line there and the real smooth lines would be basically tight curves that give you a feel from 4 Bcf to 16 Bcf if that was the tight curve associated with the data to give you a feel for the magnitude of these numbers. The jagged lines are the real data associated with the various wells that are put in these stage buckets. And the stages are four stages, 9 stages to 12 stages or less than 9 stages, 9 to 12 stages, 15 to 18 stages and greater than 18 stages. We have had some wells up to 32 stages that we have tested out here. And you can just see the performance of these wells in these various buckets and had come to your own opinion, but we have a lot of wells out here that are probably performing in that double digit reserve range. The largest well that we have book to-date has been a little over 15 Bcf. And we have got some wells with this most recent one being the 32 million a day that are most likely cliff side numbers we go through the process.
The magnitude that these wells continue to perform at is really impressive, but the fact that at the rate that they are performing at and for the duration they perform at these rates is probably even more or so when you start thinking about especially when you think about most are flowing against compression – without compression. This is a graphical area I am going to jump Fayetteville real quickly so Central Arkansas. This has been SWN’s main stay we have just great success in Fayetteville Shale. We have drilled a little over 3000 wells at this point in time in the Fayetteville Shale. We have accumulated over 3 Tcf of gas. We make – we produced approximately 2 Bcf a day gross from our operated activities.
The importance of this graph is to give you a feel for that spatial distribution of the things that are happening in the Fayetteville Shale. This represents about 600,000 acres that we – 600,000 of our operated acres. All of those grey – all of those dots represent a well. The grey dots are wells that are less than 3 million a day. The reds are greater than 5 million. And then the stars are really critical thing and these stars the blue are greater than 5 million a day and the yellow ones are the ones that we have done in the last 12 months. And what you are seeing is that we are starting to see that spatial distributions and really nice surprises come our way in the Fayetteville Shale, in fact some good things happening there. The – some of the things that are happening there one of them is that we got this great database.
We will be able to go back and mine that database and look at how some of the wells had performed from say 3, 4, 5, 6 years ago and start to apply some of that knowledge into these wells. Most recently, we have had 12 million a day well, which is in the southern portion of this acreage. So we are starting to step out into some of the deeper sections. We are having little more pressure and we have had couple of wells over 10 million a day, one well over 12 million a day and several over 9 million a day. In addition to the activities in the lower Fayetteville, we have had some very nice activities in the upper Fayetteville, which could bring to us something in the neighborhood of two or three townships here, where we could develop a number of wells in the upper Fayetteville as well.
This is the track record in the Fayetteville. I won’t go through a lot of this detail today. I think the first three sets of bars really tell the story that and this is the story, but it was really the hallmark of Southwestern, which is the vertical integration. As we talked about earlier, we have been through some really turbulent times as far as gas prices go. And if you think about it, the one thing that Southwestern has been able to do year-over-year in this program, we have been able to drive costs out of the program. If you just take a look at the blue bars, you can see that we have gone from roughly 17 days to 6 days, little over 6 days. We anticipate we will be able to carve a little bit more off of that. In 2014, fastest well we have ever drilled out here is about 3.5 days. We have had some – number of wells below 5 days, but the team continues to find ways to just we get a little bit more money out of each one of the programs.
We continued to expand the lengths of laterals. We are a little over 5,000 feet now on the average lateral, but the really key thing is that the purple curves. You can see that regardless of what’s going to happen in the increased length, we have been able to drive the cost component down to be about $2.3 million well for what we are doing in the Fayetteville and that’s what drives the economics out here. It’s just tremendous. Part of that is – the large part of that’s the vertical integration. And a big part of our vertical integration program is our midstream business. And this is one of the key things that we have (gloom) for us out here. It’s a large program. We actually gather about 2.3 Bcf a day. So all of our operated productions and third-party production, we are going to be generating EBITDA out of this program of about $350 million in 2013 and see similar number in 2014.
Very quickly, I am going to jump to the Brown Dense. It’s the newest thing that we have been talking more and more about. This is a large position we own in South Arkansas and North Louisiana. It’s an unconventional play. We have drilled 11 wells to-date. We have talked publicly about the first 8 most recently. It might be little hard to see on this graph with the one shown in red is the Sharp well. This was a vertical well that we drilled and talked about at the end of third quarter. Well produced a little over 100 days. We have shut it in for pipeline purposes. When we shut it in, we are still making over 500 barrels of liquids a day and about 1.2 million cubic feet of rich gas and we wanted to preserve the gas value there. So we are going to put it into a pipeline. We currently have in 2014, a 10 well development program right around the Sharp area, but we can also plan to drill 4 or 5 wells to help delineate the extension of the area that we have to drill outside of this area.
Last slide, I will cover here today, gives you a little information about the 2013 forecast and being that’s December 11, it’s not much of a forecast anymore, it’s getting pretty narrow as far as what the numbers are going to be. You can see that we are going to produce roughly about 654, 655 Bcf this year. We will be generating EBITDA little over $2 billion and cash flow of right at the $2 billion mark for our CapEx program of $2.25 billion. In 2014, we released guidance late yesterday if you didn’t say it, we can get you a copy of that. You see that our production targets are going to be in that 740 to 750 range, 752 Bcf range. The midpoint of that is about 14% growth for 2014. If we look at the metrics, you can see what the earnings and EBITDA is going to do. Cash flow is going to be roughly about $1.9 billion on a CapEx budget of $2.3 billion. And our debt to cap, you can see is still going to be in our 33%, 35% range, so program very similar to what we did in 2013. So that does it for me. Thank you very much for your time and look forward to working with you in 2014.
[No Q&A session for this event]
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