Bruce Vincent - President
Swift Energy Co. (SFY) Barclays CEO Energy Conference September 11, 2013 11:45 AM ET
I would like to get started with our next presentation. I would like welcome Swift Energy to our Energy Conference, speaking on behalf of the company is Bruce Vincent, the Company’s President, and with that I will turn it over Bruce.
Thanks. Good morning everyone. Great opportunity, I always love to be able to talk about our Company. Before I begin let me remind everybody that some of my comments will include forward-looking statements based on certain assumptions and need to be taken at line. Swift Energy today is primarily an Eagle Food story. We have a very high quality position in the Eagle Ford that we believe is prime to deliver liquid-rich production and reserves growth. We've evaluated our acreage. We delineated our acreage. We are moving now the process from development into the manufacturing mode that will provide both earnings and cash flow growth along with ultimately lower our financial leverage but more importantly provide predictable returns and as I will show later lower operating expense and finding cost.
We have a substantial inventory that I’ll go into a little more detail and more importantly our results continue to improve. One of things that we set out as a stated goal for this year was our 10/10/10 plan which was to improve our performance in the Eagle Ford as measured by IPs and EURs by 10% and to improve our cost by lowering them 10% and through six months of this year we’re on track with all three of those goals.
I'm going to break by talk up first to kind of give a quick synopsis over focus approach of the Eagle Ford and spend the bulk of my time on the development in South Texas. I want to touch on our Central Louisiana assets which we’re beginning to move through a disposition process and then wrap it up with a financial overview in summary.
Begin with we’re now the deploying over 80% of our capital in the Eagle Ford shale in South Texas. The current activity is focused on the liquid rich areas primarily in North AWP and LaSalle County our Artesia Wells areas, we also have a substantial inventory of natural gas projects both some condensate rich and some dry gas. We expect to have a funding gap next year of roughly $150 million current prediction. We expect to fund that through the disposition of our Central Louisiana assets which we’re on track to get bids in by the end of the year and hopefully close by first quarter. That will short run reduce our financial leverage but then subsequently that we’re going to reduce it longer term through organic cash flow growth.
Kind of a quick overview of Swift’s position, South Texas’ Eagle Ford principally and McMullen County, LaSalle County and Webb County and South Texas then Central Louisiana assets which I will touch on little bit more later which we hope to dispose and then the Southeast Louisiana which is principally like Washington Beta Shane.
One of the things that we set out for this year was we identified a number of strategic goals that we had and this was kind of our report card to day three midyear. The 10/10/10 plan which I talked about already we’re definitely on track with that through six months. We started out the year one into accelerate our drilling activity in the Eagle Ford shale while we first thought we might finance this through a joint venture. We subsequently decided that we think the best way for us to finance that is really through the asset disposition of the Central Louisiana assets. and we wanted to test the Wilcox Formation in South Bearhead Creek as to how that might respond with horizontal development. Our immediate neighbor Midstates is having some success in that both in the upper and lower and so we drilled the proof of concept well there in first and second quarter and the upper Wilcox B section and while we didn’t get the results that we hoped to get because of mechanical problems that we have, both in the drilling and the completion of that well, we did get the proof-of-concept that we had hoped to get in terms of the development of that Wilcox formation through horizontal application, and that well is now on production at about 200 barrels a day.
And we set out to test our Niobrara position up in Southwest Colorado by drilling an initial test well that was just spud, and so we should have some results on that by the end of the year. And then we have an ongoing process develop a joint venture in Lake Washington to test the Sub Salt prospect that we think has a potential of between 200 to 350 million barrels.
South Texas, kind of a quick overview of our position, McMullen County is the largest acreage position and we’ve been in McMullen County primarily developing the Olmos [indiscernible] sandstone for 25 plus years. LaSalle County, which is our Artesia Wells Eagle Ford area and then Webb County which is the Fasken field which is a dry gas area but it’s very, very proliferated Eagle Ford rock and in fact just its economic at a 350 gas price but the economics accelerate exponentially particularly as you move from 450 and above so we think that’s a really good future area for gas development, all that acreage is earned.
In South Texas we’re going to continue to focus on the liquid rich areas, which is primarily in that North AWP area and LaSalle County area. Most of our high valued liquid rich Eagle Ford is earned, if it’s not earned yet, it will be earned with the activity that we have planned. Some of our dry gas acreage is earned, some of it’s not. We’re not too concerned about that expiring, because we think that’s very releasable if the gas market comes back.
Other things we’re trying to do today is improve performance and decrease your cost. These resource plays are a margin business and so you need to focus on optimizing performance at the same time driving cost down. And you see us doing that in a number of ways with our 3D in the area really helps facilitate placement of the laterals. When development of the Eagle Ford started out you’ve got an Upper and Lower Eagle Ford section, the Lower Eagle Ford is roughly under 150 feet depending upon where you’re at and generally the industry just figured you place a lateral on the lower Eagle Ford pretty easily to do frac the well and get the results. We’ve actually identified about a 30 to 40 foot section of that Eagle Ford and the Lower Eagle Ford that has a higher level TOC to our organic content has better porosities and we believe the rock is actually more brittle.
And we have found from horizontals that stay in that particular horizon that we get significantly improved results. And so we’re now using our seismic attribute analysis to identify that section when we drill our Eagle Fords and try to keep our wells placed in that 30 to 40 foot section and we’re improving results as a consequence.
We’re also looking at ways to improve completion results. In particular, we’re logging the horizontal section of that well, indemnifying places that we don’t think are fracable and so we’re actually eliminating stages, that’s reducing cost. But we’re also getting equal or better than results from the proper placement of where those stages are after logging that lateral. We’re seeing improved frac performance from the continual kind of redesign of our fracture stimulation process and all of that is leading to this improved performance both in terms of IPs and two year tames and EURs.
We’re seeing drilling times reduced and we’re also seeing drilling cost reduced not just from the time, reduction in time, but also from other efficiencies that we’re applying to the process and we’re seeing the same thing on the fracture stimulation completion side, both improved execution times, which reduce cost, but also other efficiencies brought to bear that are reducing cost. And all the marketing infrastructures in place and been in place for some time, so our ability to get the product out in the market is well established.
Three key things we’re doing: we’re exploiting the high value of the Eagle Ford acreage, we’ve got 340 million barrels in that resource potential in this high value acreage position, we’ve planned over 80% of our capital there, we’ve drilled over a 100 Eagle Ford wells to date so we know what we’re doing, we’ve got approximately 600 drilling locations based on current well spacing which is a 60 acres spacing size in these high valued acreage and we continue to see improved performance both in terms of IP rate, EURs and well cost.
So specific examples to this on the IP side, one of the things that we do is we consistently measure and report our IPs one well into the next in the same way that allows us to benchmark IPs. Now I think IPs are only a useful tool for certain things, it’s not the end all be all in terms of performance but if you’re consistently benchmarking it one well to the next, in other words measuring in the same fashion, it becomes a benchmark to look at well to well performance and we see our IPs actually increasing just the first six months of this year, 18% in our Artesia wells area and 15% in the North AWP areas. So, we are on track to meet that 10% improvement in those two areas.
On the cost side we’re seeing the same thing. We’re seeing a 13% decrease in our drilling and completion cost in our Artesia wells and a 16% decrease in drilling completion in North AWP, you will note by this chart that there are wells in Artesia wells are actually cost less than they do in North AWP and there are principle reasons for that. One, they are a little shallower but very importantly the geology is a lot quieter and so it’s more efficient for us to drill those horizontals and to place them where we want to we can actually do it quicker.
This is really a step-by-step progression of how we’re improving or decreasing drilling cost, it’s not a one thing that you’re doing, it’s a step-by-step progression of a number of things that you’re doing to try to improve and reduce those drilling cost. This slide represents the same thing but with regard to completion cost, what you’re doing from a time standpoint, we have the same kind of data, it’s also piece-by-piece process, it’s not one thing that you do it in the decrease is caused, it’s a series of things that you do some of which is efficiency improvement, some of which is changes in design or other supply chain management impacts at reduced cost.
This slide really puts it all together and the key thing to look at on this slide is not the bars that everyone might focus their eyes but those green boxes, this shows you the progression of drilling and completion cost improvement since 2010, we started at drilling wells for roughly 11.5 million at first year (audio gap) up about $2 million down about $9.5 million and next year you knocked off another million down about 8.5 million and this year through first six months we’ve knocked off another million down about 7.5 million so that continue the improvement we think there is still further improvement to be made particularly as we moving into manufacturing process.
What are we getting for that, we’re obviously getting substantial reserves growth, this is just an Eagle Ford reserve growth, basically in 2009 was nothing to little bit in 2010, the substantial growth in 2011 and further growth in 2012.
Same thing on the production side, you can see we’re actually know Eagle Ford production prior 2010 and it’s -- while it’s been a little lumpy and that’s the nature development particularly when you’re doing two, three or four wells you’re seeing the continual growth in that production and we continue to believe that we’ll progressed as we move forward and focus on the Eagle Ford.
And this slide is a little bit complicated. So, let me just kind of bottom line it for you but this is a map of hydrocarbon pore volumes over the Eagle Ford across all of South Texas in the purple means you have higher levels of hydrocarbon pore volumes and that white line really is what I’m going to show you in a minute is a cross section that incorporates our Webb County Fasken area, with our LaSalle County Artesia Wells area, our north AWP area and ties it in with the DeWitt County, Karnes County trough which many people are familiar with, where you have some really-really prolific Eagle Ford wells over there.
The next slide really shows you that cross section again, I know it's a little bit complicated for a slide but if you just look and this is actually flattened on the lower Eagle Ford, which you can see those blue lines run across at the bottom of that, but if you just look at that marked green section, the Eagle Ford rock in Fasken, LaSalle County, McMullen County and DeWitt County, you can see the quality of the Eagle Ford section in all three of our locations, is very comparable to the quality of the rock up in the Karnes County trough.
The other thing I mentioned earlier was how this focus on the Eagle Ford will reduce our overall cost and to give you a little flavor for that, if you look at our LOE and our Texas translation processing costs in South Texas, and compare those to our other places of operation, you can see as we direct capital and grow production in South Texas versus Louisiana we're going to actually lower the overall LOE and transportation and processing cost for the company.
And I want to touch quickly on the central Louisiana divestiture, we've decided that we're not going to allocate capital to these properties, we think these are terrific properties and if we had lots of capital we would continue to develop the chalk and the Wilcox in particular, but we're limited in the amount of capital we have, we think the best place to focus our capital is really in the Eagle Ford in South Texas so we think these assets are really more valuable to someone who's going to have current drilling activity and so we're started a process to dispose of those, we engaged am intermediary. We're in the process of going through the detail to set up a data room, we would expect to have a teaser out by the end of this month, we would expect to have bids in place by the end of the year and look for probably a likely first quarter close. Property basically consists of the Austin chalk, producing properties that we have along with acreage in Burr Ferry and Masters Creek in addition to the work and interest that you're used to seeing with people we’ve got a substantial mineral interest across that that actually makes this much more valuable from an operator perspective because it takes away any time clock and it also gives you upside in other areas other than the Austin chalk, either Wilcox, or Tuscaloosa marine shale are some examples, some of that northern Burr Ferry acreage where we have minerals is prospective for the TMS.
We're not actively going after that because we don't have to, we're actually watching the industry develop it, but there is some prospectivity there. South Bearhead Creek is a Wilcox field that we developed vertically both in the upper and lower that's the one that we drilled the first horizontal in and we have some offset operators that are also successfully developing both the upper and lower Wilcox horizontally so we think that also represents some substantial upside.
We look at that production it's roughly about 2,400 barrels a day, currently we're about to put on a new chalk well out of Burr Ferry that's in our joint venture with Anadarko that will certainly take that above 3,000 barrels a day, so that's the kind of production that we would expect to be divesting. The financial side real quickly let's look at the cap table both at year end and June 30, I think a couple of key markers that I look at debt to cap is 49%, that's not overly leveraged we think it's a leverage level that we start to exceed our comfort level in so we really don’t want to get it much beyond that and that's the reason for the asset disposition is because we want to accelerate activity in the Eagle Ford which means you got to outspend cash flows, we want to fund that gap really with an asset disposition, I think if you look at the cash flow to debt metrics in this case we decided net debt, our last 12 months EBITDA 2.7 at June 30, and then debt to capital of almost 50% and then debt to year and pre-reserves are about 540. The budget is out this year, we expect to spend $500 million to $525 million, next year we have not established a budget yet but we have given some preliminary guidance spending at roughly about $500 million worth of four well or four rig program active in the Eagle Ford.
Most of the capital is going to be spent on development just as it was this year and with that capital spending program next year we would expect to get 8% to 10% production growth inclusive of the asset disposition. In other words we would make up the loss of that production plus grow 8% to 10% on top of that. So the actual growth in this South Texas Eagle Ford would be greater than that.
To wrap up, very focused on the Eagle Ford, aggressive development of that asset. It is in fact a very high quality asset, it is our most predictable, it is the one that we have the best line of site on, while we had looked at possible JV for that, we really think that the best way to do that is to keep at 100% of ourselves, we didn't really like the idea of selling part of it to somebody else because we continued to see these improvements both in terms of IP and EUR or other performance metrics and also decreases in costs.
So our economics just continued to get better and better and we just want to keep it ourselves, plus it provides a very predictable and much lower risk path for us to grow production, grow cash flow and drive our leverage down.
We're now in the process really of moving beyond the pure development stage and moving into manufacturing mode that will allow us to both speed it up or accelerate it but it will also allow us to continue to bring some other efficiencies to bear particularly in terms of cost reductions, both in the drilling side and the completion side.
We need to focus on the Eagle Ford particularly in the liquid rich areas until the gas market turns around, we'll ultimately help lower our leverage we'll bring cash flow growth and earnings growth to the company. It will provide like I said much more predictable and definable set of results, and it will lower the company's overall operating expenses as well as our finding cost.
I think we have established earlier that we have a significant multi-year inventory in these liquid rich areas and we believe that the gas market will improve and some of areas like I mentioned fast and even at a 450 number have actually very substantial economic returns and very durable at those kind of levels.
And more importantly what we're finding in terms of our actual results is we’re able to improve our results. So resource players are in margin business, so you are working to optimize your performance, optimize the manufacture that product, in case producing hydrocarbons. And we're seeing that as measured various performance metrics but couple that we have decided our IPO rates and EURs, we’re actually looking more at the two year and kind of market them against past two year tunes [ph] we think that's a better measure. We don't believe any of us in the industry really knows where that decline curve is going to cut during hyperbolic act, and so we think looking at 30 year or even more than that EUR is not the right way to benchmark yourself. But looking into two year tune [ph] was a pretty good way to do that, and we’re seeing improvements on that on our actual results and we’re clearly able to drive our cost down both on the drilling side and the completion side and we see as we move into this manufacturing mode, we believe there are number of ways to continue to drive those costs down, ultimately expanding that margin that we have for the Company.
I appreciate the opportunity to talk to you and appreciate you listening. I think we're set up in a breakout room and we'd be happy to go and answer some individual questions.
If there are any questions here we can move straight to the breakout room which will be in the Liberty 1 and 2. I would like to thank Bruce and the Company for coming to our conference.
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