Swift Energy Company (NYSE:SFY)
2013 Analyst/Investor Meeting Call
March 14, 2013 9:00 AM ET
Terry Swift – Chairman and CEO
Bob Banks – EVP and COO
Steve Tomberlin – SVP, Resource Development & Engineering
John Branca – VP, Exploration & Geosciences
Alton Heckaman – EVP and CFO
Bruce Vincent – President
Neal Dingmann – SunTrust
Leo Mariani – RBC
Brian Kusmo – George Weiss
Michael Hall – Baird
Andy Coleman – Raymond James
Steve Barman – Canaccord
Mark Lear – Credit Swiss
Wilson Sbatcher – Johnson Rice
Hello and welcome to the Swift Energy 2013 Investor and Analyst Day. Thank you so much for taking the time to join us today. Just a couple of minor notes before we begin.
Today, our presentation is going to be webcast so we just ask that you keep that in mind throughout the presentation keep the phones on vibrate, realize that a lot of folks here in the room in Houston are going to be doing some work while they’re participating in the event. But we definitely have a larger audience in here I just ask that you keep that in mind.
As far as the program today, we do have a few notes regarding the building the room here, should there be some type of event or emergency or fire, the hotel here will make an announcement and give us instructions but generally we’re going to want to exit to the rear of the room and follow instructions from there.
We also have some limited first-aid available to folks if anybody has some issues that require that type of attention this morning, we’d be more than happy to help you out with that, just find the women in the back of the room and they’ll take care of what you need. We do have some food, breakfast for you if you haven’t had a chance to enjoy that yet, please do so.
As far as the presentation is concerned, when we were informed last week that we were going to lose an hour, we’ve shortened the presentation by an hour of course and then somebody explained to me what daylight savings time actually meant. So, we spent the last couple of days adding back that hour but I think that will have better four-hour presentation for you today. And it should have a lot of good content.
You have an agenda in front of you we are going to have one scheduled break. We’re going to do our best to stay on schedule and we just ask for a little bit of help with that. As you need to take breaks, please feel free to go grab some refreshments or visit the restrooms. But when we do break, we’re going to ask that you promptly come back to the room on time and help us keep this thing moving along.
That being said, it is always a distinct pleasure and honor to introduce Terry Swift, the CEO and Chairman of Swift Energy, he’ll take you through a brief overview of what we’re going to be, trying to accomplish here today.
Thank you Paul, and thank you for joining us today here in Houston for our meeting. And those of you that are listening in through the webcast we appreciate your attention there and listening in as well.
Today, what I want to do is be very candid, be very open, be very transparent about the company, where we’re at today. The metrics that we’ve brought forward today from the asset base and from the organizational skill-sets we put together. But I also want to talk about the milestones for 2013 and how we are going to move our metrics and move our values from these different properties forward, we believe that we can demonstrate to you today, some accomplishments that the company has had. Some of the asset values that we are in responsible charge off. Our plans for those assets going forward, the milestones that we’ve set for ourselves and then a nice look at tomorrow and the future and how the company believes it can grow.
I want to start with 2012 and focus here on some of our highlights, some of the actual results and metrics that we achieved. Reserves volumes grew 20% year-over-year. Our PV10 value increased 19%. Liquids reserve, a very important objective of the company, these reserves grew 63% year-over-year. South Texas production volumes where we’ve been spending most of our capital grew 44%, and the total company production grew 11%.
Now as I’ve noted and as we’ve said before, the strategy has been to focus on liquids, our crude oil and liquid rich gas areas, growing Eagle Ford production and reserves profile, we’re going to demonstrate that today. The status of those assets, the quality of those assets, what we believe they can deliver. The activity that we set out for 2013, we’re going to show you in great detail how it supports production growth. But it does so with 30% to 40% less capital than we used in 2012. And of course we want to make sure that it’s recognized that we do receive some very good and significant pricing relative to HLS and LLS pricing in all of these liquids areas.
Again, focusing on today, we want to make note that we do have high margin production from what would be referred to as our legacy assets, about 40% of our revenue came from those assets, and Louisiana, Lake Washington and Burr Ferry last year, that’s changing. We’ll show you how we’re diversifying as we go forward. We do have line of sight growth, call it at some time strategic growth, sometimes you might refer to it as business plan. But clearly the four areas where we’re going to show you in great detail, the quality of the assets, the plans around those assets, they exist today.
In Texas in particular we have the Eagle Ford and efforts have been underway to not only enhance the value of those assets and prove the performance of those assets but to determine how much reserves can be brought forward either by accelerating the drilling or by down-spacing, we’ll show you some of those results and what we believe some of those volumes and values can be. Here, we’ve given you a little head-start, 244 million barrels of oil equivalent, we’ll show how that’s diversified as a resource potential.
Louisiana, we already have underway, a horizontal Wilcox well in our South Bearhead Creek, that well is targeting tight oil. And the opportunity in both the upper and lower Wilcox we’ll get in today. But again resource potential in the range of 20 million to 28 million barrels of oil equivalent, and that’s in the near term horizon.
South West Colorado we have the Niobrara, another oil play, resource potential up to 200 million barrels of oil equivalent. And one of our favorites that’s been with our for a while but hiding underneath the salt is our sub-salt Miocene resource potential of 200 million to 350 million barrels of oil equivalent in the Lake Washington area.
The company finds itself today with financial strength, stable capital structure with financial flexibility and ample liquidity. Our funding is in place for activities. And we do look at ways that we can accelerate or bring other types of funding vehicles forward to enhance the value of these assets. And again today we’ll show you not only where we are today but some of the milestones for 2013.
As we look at 2013, we want to focus first on what we referred to as our bread and butter, we’ll give you a lot of information today about South Texas operation, what we’ve learned there, the continuous improvement in our organization as well as the industry has experienced there. We’ll show you why we believe that as a milestone we can set IP improvement goals of 10% or more based on recent results both oil and condensate areas of our assets.
We also are setting a milestone of a 10% increase in our ultimate recoveries. We’ll show you why we believe that today. And we are bringing cost down, collectively both increasing production on a per-project bases, completing reserves on per-project basis and lowering cost is a milestone objective for 2013.
Just a little bit of an example upfront in the presentation, again I don’t want to take the wind down to the sails. Our folks are here today to demonstrate to you with a lot more clarity and a lot more precision, not only why we believe we can meet these milestones, but the underlying physical properties and operational changes that have been going on to enhance the value.
Here by example, on this slide titled operational improvement in South Texas, we show some initial production rates over 100 and actually it’s more than initial production but production over 180 days. And we show that our most recent seven wells are performing materially better than original wells that date back, we’ll go into that detailed in the presentation. It’s very positive outcomes coming from the way we’re conducting our operations.
Again milestones for 2013, South Texas Eagle Ford Program, again I’ve noted that we’ve developed and identified a significant amount of resource potential that is really beyond the five-year type rules that we have for how we book, we’ve also been looking at how we can down-space and we haven’t booked those reserves. So as we look at that reserve potential and we look at how we could accelerate the development of this area. We have to consider that would improve our cash flows and growth activity.
And therefore we are looking at creating a joint venture that would improve the project returns that’s the first goal but also achieve near-term value recognition that we hope today, you’ll see as well, I’ve said in several conversations as we prepared for this meeting that today’s objective is not be all to end all. We recognized that we need to take these milestones and demonstrate them to you, show you these assets. And why we do believe we can improve the project returns and why we do believe we can get better value recognition. We’ll show you that today. Again this is only the beginning of the course that we’ve charted out for ourselves. But nonetheless the plans are in place and you’ll see that today.
Central Louisiana, another 2013 milestone we’ve set for ourselves. Again, I’ve noted that this well, or this first test well is already underway. We expect this horizontal Wilcox well to be completed sometime in the second quarter. Just a little bit of a hint on how this project is shaping up for us. We believe based on information again we’ll show you today that we can achieve 800 barrel a day initial tests, primarily oil and that our expected ultimate recoveries from these projects would be in the range of 500 million to 650 million barrels of oil equivalent.
This sets up at least 20 additional locations in the upper Wilcox, again we also have the lower Wilcox that we need to consider as we look forward to this near-term upside. But again, the range of resource potential is 20 million to 28 million barrels of oil equivalent.
Moving to slide 12 which is titled the Southwest Colorado Niobrara test. This is another area we’ve been working on. We’re looking again on an oil play, we’ve already amassed 70,000 gross acres, 50,000 plus net perspective acres in the area. We do plan on having a test in the third and fourth quarter of this year as one of the milestones we’ve set out. Again, a few expected IP levels on this slide presented 375 to 700 barrels a day, initial test expected is what was EUR in the 250,000 to 400,000 barrel range, we’ll get into this project and what we think can be levered both in the way of timing and cost later in the presentation. It does provide for us, going forward a multi-year inventory of low lost oil drilling.
Again, moving forward and just giving you a few more details on Southeast Louisiana and what are the milestones we’ve set for ourselves and the sub-salt Miocene project. We do plan this year to have a very rigorous well-designed and a partner secured we then definitely want to move forward and we’ll announce that as we achieve our first milestone but we do believe at this point in time and we’ll show you that information there that our target is 200 million to 350 million barrel oil equivalent.
And a little known fact in terms of people that have been following this project from a distance but a fact that people up close to this area would be interested in is we are keying our target off of a down-dip well that was logged and cored in 1990, that did show oil shows down-dip from our target, we’ll get into that detail again today and give you a much better understanding of that project.
Let’s talk for a minute about tomorrow before we asked our operations folks to dig into the detail. And I think it’s clear that tomorrow or the future, we want to be able to come back to you and demonstrate that we’ve enhanced the operating efficiencies and that operating enhancement has resulted in our core areas generating higher returns and cash flows for dollar invested. We want to demonstrate that we have improved operational metrics relative to our past.
We also want to make it clear that South Texas is a strong asset. We want to be able to show you based on our future operations that the Eagle Ford well performance not only is improving but we’ll continue to improve as we have more precise lateral locations drilled in these higher quality parts of the rock, we’ll show you again today how we’re moving towards continuous improvement both geologically, geo-physically and in terms of the completion of both drilling and frac stimulation that’s going on.
And of course, we want to be able to show that we can down-space the Eagle Ford, as I noted earlier. I was going to show you some of these test results for our down-spacing in several areas and what we think that means for the company in the future.
Again, tomorrow we want – or in the future we want to be able to come to you and talk about our strategic growth. We’d like to be here talking about three projects that were crude oil projects. And we want to be able to demonstrate that we not only have recognized the Wilcox asset value but that has been drill-tested. And we’re of course looking for success there. South West Colorado again, that will give us a multi-year inventory. And we’re going to be able to come to you and tell you that we’ve logged, we’re cored it and we’ve tested it.
Sub-salt, again we want to be able to come to you and say, based on the achievement of our milestones, we do have a high quality partner form to explore the sub-salt in the Lake Washington.
We also are clearly focused on our oil project inventory and the creating of a joint venture opportunity, where we can bring meaningful reserves that are out in the future forward through initial drilling success. And of course all of these things play well to 2014 and beyond and how the company will grow.
Just two more slides here at the very end of the presentation. Slide 16 for example, titled Swift Energy Company portfolio growth and diversification. I’d like to demonstrate how we have succeeded from 2008 to 2012 in growing the value of the reserve base. And changing the distribution or better diversify the reserve base.
2008, our PV10 was $1.4 billion of oil equivalent, Southeast Louisiana was the lion’s share of that. By 2012 you can see that we’ve moved very significantly to a $2.4 billion asset base with significantly better diversification between South Louisiana, South Texas and our other assets.
Finally, I’d like to focus on our reserves and again our volumes have grown significantly from 2008 to 2012, 2008 year-end volumes 116 million barrels of oil equivalent, 2012 year-end volumes 192 million barrels of oil equivalent. And again, the diversification has changed from South Louisiana, or Southeast Louisiana being the lion’s share to Texas now being the lion’s share where our growth is presently.
With that introduction and that plan, again brought before you that we want to achieve today showing you what we’ve done in the way of our metrics, where our assets look like the value we believe is there. We want to show you our milestones that we’ve set for ourselves in 2013 and how we’re going to achieve those. And we want to show you how tomorrow we’ll grow the company.
And with that, I’m going to turn it over to Mr. Banks. Thank you.
Thank Terry. Good morning everyone. I want to start out just with a little overview like we typically do at where our core operating areas are. You can see starting in the Texas area, the Fasken, Artesia Wells, Sun TSH and AWP areas and the Eagle Ford in almost 2012 we had about 23,500 barrels of oil equivalent per day coming out of this area. And that area is responsible for about 157 million barrels of oil equivalent of reserves base.
Moving up into the Central Louisiana area, that’s primarily our Austin Chalk and now our Wilcox areas, last year we had about 2,500 barrels of oil equivalent coming from that area and responsible for that 20.4 million barrels of oil equivalent reserves base.
And moving down into Southeast Louisiana, Lake Washington beta Shane fields, our production there was a little over 6,000 barrels of oil equivalent per day. And we had year-end proved reserves about 15 million barrels of oil equivalent. And probably for the first time now, we’re showing you our Southwest Colorado Niobrara position up in the four corners area, about Southwest Colorado.
So, I want to talk a little bit about our operating achievements this past year. First of all, we are demonstrating some strong liquids rich reserve growth. We’re going to talk about our solid high value liquids rich production growth. Thirdly, I want to talk to you about our continued capital efficiency gains. We want, as Terry touched on talk more in detail today about our improving IPs EURs and down-spacing opportunities in the Eagle Ford. And we want to talk to you about how we’re trying to develop the portfolio strategically.
So, first reserves growth, Terry touched on this, I’ll go through this in a little more detail with you. We did have 20% reserves growth this past year and that’s strong growth for the third year in a row. We had 63% liquids reserves growth this past year. So we think we’ve done a pretty good job of converting in to drilling into to liquids area and turning that into value for our shareholders.
Our net present worth has grown from – to about $2.37 billion or about 19% even with some lower commodity pricing that I’ll show you in a second. Our year-end product mix has improved from about 36% at year end 2011 to 48% year end 2012. And 2012 did represent the largest yearend reserves position in the history of Swift.
But in South Texas, which is where we’re spending a lot of our capital, especially last year and the year before as we worked through this Eagle Ford play position. We grew our liquids reserves 122%. And we grew our total reserves 27% in South Texas. And we’re going to show you more about some of the successful down-spacing that we’re achieving both in McMullen County and LaSalle County. And we think that gives us a lot more running room in the Eagle Ford.
Just to touch a little more on the reserves reconciliation. You can see that we began the year this year with about 36% liquids. We added about 56.5% liquids through our activity this year in discoveries and extensions. And now to improve our yearend numbers that I mentioned earlier to about 48% liquids.
If you look at the top of the chart here on slide 25, you can see our PV10 value at about 1.99 billion at the end of 2011 that was with a pricing deck of 96.04 oil and 4.16 gas. We even despite some of the deterioration last year especially in the gas markets, we increased our PV10 value to 2.37 billion at about $1.30 in MCF less gas and about $1 less per barrel on oil price.
Looking at our PUD venturing by value, you can see that the bulk of our value is really time present. But then all of our PV10 value in our PUDs really rolls together in a five-year period. So we’re in very good shape under the five-year rules.
A little more to tell on total reserves growth. If you look how we’re done, we’ve grown about 62% in reserves since 2010. if we take into account our 2013 guidance that we’ve set for you, three year liquids growth would be about 70% during that same period.
Looking at Texas specifically, again where we’re spending a lot of our capital, we’ve grown our reserves 122% but we’ve also grown our liquids by about 192% over that same period.
Proven reserve compels and end of 2012 the where we think we’ll be end of 2013 based upon the guidance, a slight improvement in our liquids mix by year end this year. So we’re continuing to work for liquids throughout 2013.
If you look at where we’re going to get our reserve adds this year, on the left is a pie-chart that basically says the reserve beds by well type. So, what we’re showing here is that all of the drilling activity that we’re going to add reserves on this year will come either out of oil wells, wells classified as volatile oil or more liquids rich wells about 48%. And then, if we look to the right pie that’s reserve adds by product. So there you have about 66% liquids and 44% associated gas.
Just a little on our finding and development cost. In 2010 our F&D was about $14.90 a barrel that was for 33.5% liquids. And again, what I’m doing here now is I’m really only looking at the discoveries and extensions, I’m not taking into account any revisions to reserve that what did we actually discover in the ground. So, it was about $14.90 that fell in 2011 to about ‘11 ‘12 but a lot less liquids, our 2011 about 17.8% liquids. And then you can see what we did this year in 2012, about $16.36 for 56.5% liquids. So, we’re increasing our liquids in that F&D cost.
In Texas, going back to 2010m $8.17, 2011 $8.34 but again not that much liquids mix. And then you can see how we’ve really stepped up the liquids and calculate now a $13.18 but just about 55% liquids.
And then just comparing the overall 2012 F&D cost, where we’ve been putting our money and actually discovering reserves to put on the books. Texas Eagle Ford and Olmos about $13.18 for that 55% liquids and you can see we introduced the Austin Chalk because we did drill some wells in the Austin Chalk and put some reserves on the books from that area at about $10.56 and that’s about 66% liquids.
So, moving to production growth, going to slide 35, our production volumes this year grew 11%, about 1.2 million barrels of oil equivalent. It did represent the highest production volume in the history of US for Swift Energy Company. And we think our company-wide liquids production is a lot more robust now due to the expanding liquids rich portfolio of the Austin Chalk Eagle Ford and Olmos properties.
In Texas, our production grew in liquids 68% in 2012 and our overall production growth in 2012 was 44%. So, just looking at the same trends of production, you can see that 2010 through guided 2013, a three year growth of about 45% and a liquids growth of about 25%. If you look at Texas, a three-year growth of 162% and a three-year liquids growth of about 152%.
So, I want to move a little bit into the capital deployment. As Terry mentioned we have some achievements and we have some milestones here. In 2012, our drilling cost steadily decreased throughout the year, about 15% or about $700,000 per well when you equalize lateral length and cost per foot.
Our drilling days per well steadily decreased throughout the year, about 22% or about 8.5 days. Our frac stage execution steadily improved throughout the year, to where we were averaging about four to five frac stages per day to by the end of the year about 7 to 8 frac stages per day. And our cost for frac stages improved during the year as well by about 11% or about $585,000 despite what we all know was a spike in oil pricing during the third quarter and even into fourth quarter last year, we still were driving our cost down.
And as you’ll note, we did spend a fair amount of money on significant facilities and infrastructure in our Eagle Ford position. And that’s going to help make a lot of our development drilling and manufacturing drilling a lot more economic and timely to post production.
Just to touch on drilling performance, you can see the codes, starting in the upper left side, the first quarter average well about 3.7 million for about 5,218 foot average lateral length. By the fourth quarter about $3.5 million but the lateral length during that quarter was about 6,128 feet average and that’s in Artesia Wells.
Moving over into AWP in McMullen County, started off at about $4.7 million average for a 5,100 foot lateral, by the fourth quarter we were drilling about 5,650 foot laterals for $4.1 million.
Looking at our three-year trends, we think we’re trending in the right direction both in terms of days on wells from 2010 to 2012. We’re generally trending in the right direction bringing those days down. If you look on the right side, the lateral lengths, even though we’re driving days down, lateral lengths are going up just about in all of our areas.
On the – some of the performance indicators, foot per hour, generally trending in the right direction over the three year period. Cost per foot, generally trending in the right direction. And per set of non-productive time, which is NPT, mixed, I can say we made great progress in AWP Eagle Ford and the AWP Olmos areas.
Completion’s performance. This is a chart here on slide 45, that shows cost per stage that’s in the light blue. So you can see in 1Q 2011, kind of where our cost structures were per stage. And then by 1Q 2013 where they are now and we kind of show you the wire increase period where we had about $21,000 of stage increase in wire costs. And we were still able to manage through that and keep our costs coming down.
The red and the blue charts, the blue is the number of wells stimulated. You can see, we’ve increased the number of wells stimulated. The red represents again non-productive time. And you can see that we improved our non-productive time significantly over 2011.
So, this is just a cost evolution now in the next slide, Texas completions. 1Q 2011, we were about $312,000 a stage for the completion. And you can see some of your initiatives that we undertook to drive those cost structures down that by 4Q 2012 we were down to about $228,000 a stage. And now in 1Q 2013, we’re about $209,000 per stage.
So, what can we do in 2013 and beyond? Well, we think there is more capital efficiency to be had in the Eagle Ford and Olmos. In drilling we’re going to forecast for the operating guys about another 4% to 8% reduction in drilling costs in 2013. On the completion side, we had released our dedicated frac fleet and we are able to do that for a couple of reasons, one, there is better market conditions today than there was two years ago.
We have less activity in 2013 so we worked out an arrangement where we’re going to keep the same tax spread in crude but not on a dedicated basis and there will just be time to our well delivery structure. And that alone is going to drive our cost down quite a bit more. We forecast about another 8% to 10%, about $420,000 reduction in our fracture stimulation cost.
And then, as we move beyond 2013 and really get into the pad fracking and some more efficiencies that we can get to, when we’re really in development manufacturing in these areas, we think there is another 5% to 8% that we can have on the completion side. And then, facility as I mentioned, we did spend a fair amount this past year, we expect our facility and infrastructure investment to about 40% lower in 2013.
Okay, Terry touched a little, we’re going to get into this a lot more when Steve comes up. But some of our improving IPs, EURs and down-spacing, we’re demonstrating it now, both in the South County, in the Eagle Ford oil and condensate models. And we’re also demonstrating it into McMullen County, Eagle Ford oil and condensate models, as well as the Olmos oil models.
How we’re doing it is by using our 3D seismic and doing attribute analysis by our geo-technology group. And they’re now narrowing the target zone and identifying the best rock within the lower Eagle Ford to land that lateral and steer that lateral in.
And this target zone that we have identified and we’ll show you a little more about has higher TOCs in it. It has better porosity and it’s more brittle which allows us to get a more effective fracture stimulation around it. And we think this has been very key to some of these improving EURs and IPs that we’re going to show you.
We’ve also done some successful down-spacing tests in both McMullen and LaSalle. We think overall that should add about 30% more locations into our Eagle Ford position.
Okay. Moving to slide 51, what I’m showing here is 2012 model versus some recent performance IPs in barrels oil equivalent per day. Now these are normalized on a actual test data anywhere from about 7 to 30 days but normalized when we release our flow back crews and turn the wells over to production.
So, the Eagle Ford oil and McMullen, we’ve increased that to about 11.08 from 8.80 a day and the Olmos oil, we’ve increased that to about $1,050 from about $900 in the Eagle Ford oil and condensate blended models about 14%. And in the Olmos condensate in McMullen County about 7% increase based upon actual extended term testing.
Translating that into EURs that will show you more – here more detail in a minute, the Eagle Ford oil, we think we’ve increased our EURs on recent wells by about 19%. The Olmos oil in McMullen we’ve increased by about 20%, the Eagle Ford oil blended models about 7% and we’re leaving our Olmos condensate EURs pretty flat.
So, Terry mentioned developing the portfolio strategically what we’re trying to do here. We think over the past four years we had diversified the portfolio to give us better performance certainty and repeatability. Additional liquids rich plays have brought a lot more balance to our portfolio and more predictability under the portfolio. And we’re getting this through the Texas Eagle Ford, Texas Horizontal Olmos, in the Burr Ferry Austin Chalk.
We got some new liquids rich plays we’re going to talk to you about today. Central Louisiana Wilcox, Southwest Colorado Niobrara and the Sub-salt that Terry mentioned.
So, just looking at the revenue source, we think we have a much more diversified revenue source for Swift Energy Company. The pie-chart on the left was our 2009 revenue source. You can see we got about 65% of the revenue out of the South Louisiana Miocenes. And about 20% of our revenue out of the South Texas vertical Olmos wells.
On the right chart 2012, we now are deriving about 38% of our revenue from the South Louisiana Miocenes, 32% from the horizontal Eagle Ford’s 20% from the Horizontal Olmos. And we’re ramping up our Austin Chalk.
We think the production base is more solid than it was in 2009. And 2009, right about 55% coming out of the South Louisiana Miocenes, and about 29% coming from the Olmos Vertical Olmos wells, gas wells. By 2012, our production source is about 19% in the South Louisiana Miocene is 44% in the horizontal Eagle Ford’s 29% in the horizontal Olmos and ramping up some in the Austin Chalk.
And then our reserve source I think is a lot more predictable that it’s been. In 2009 we had about 38% of our reserves in the South Louisiana Miocenes, 38% in the Olmos vertical gas position. And then in 2012, our reserve source is really shifted about 8% now in the South Louisiana Miocenes, 63% Eagle Ford, 18% in the Olmos. So, I think a lot more predictable reserves and production base for us now.
And we’re also working more strategically with partners in some of our various areas. As an example, in 2012 we drilled four joint-venture wells, with Anadarko in the Burr Ferry area. We drilled four joint venture wells with BHP Beleton and Texas Eagle Ford. Three joint venture wells with Valhousen in the Eagle Ford and we did a nice acreage transaction with Matador in the Texas Eagle Ford.
So, 2013, we do contemplate some more partner activity. We do want to bring in a partner to help accelerate development of our high value Eagle Ford position where we have those reserves. And we want to form a joint venture team to do the exploitory sub-salt testing Lake Washington.
And just kind of shows you in 2009, on the pie on the left, on slide 59, we operated everything 100%. In 2012, about 17% of our wells were partner oriented. So, it’s something we want to continue to do.
So, today, we’re going to talk about both development and projects and strategic growth projects. First off, Steve Tomberlin is going to come up and talk to us about our development projects. And we’re going to talk to you specifically about two focus areas. First AWP and the Artesia Wells, Eagle Ford Shale, this is where we have a multiple year inventory for development potential. Oil and gas condensate acreage throughout and all of our 2013 activity is focused on liquids rich drilling.
The AWP Olmos tight sand, again some multiple horizontal, multiple year horizontal opportunities in the AWP Olmos tight sand in the oil and gas condensate areas and again, 2013 will be focused on the liquids rich portions of those plays. So, what we think we’ve been able to do over the past year or so is really high grade the areas where we want to drill, apply our technology, apply our capital deployment and really improve our project metrics in the Eagle Ford.
Southeast Louisiana, Steve is going to talk about Lake Washington Beta Shane, we had some oil and high oil opportunities across a variety of risk and reward type opportunities. And then in Central Louisiana, we’ll talk more about Burr Ferry and the potential for multiple year, horizontal development there.
Then John Branca will come up and talk about strategic growth projects in Central Louisiana, he’ll update you on what we’re doing in the Central Louisiana South Bearhead Creek field in the horizontal Wilcox program. And why we like that opportunity.
In Southwest Colorado, we’ll talk about horizontal Niobrara test, this is an area where we have a large resource play. It can yield significant reserves and production growth for many years, if this is a successful play for Swift. And then of course Lake Washington as sub-salt is a tremendous opportunity. It would be a very meaningful oil target that could really transform Swift Energy Company. it’s a project we would do in a partnership where we would manage our risk profile in such an opportunity, but it’s a wonderful opportunity and I think you’ll see its merits when John shows it to you here shortly.
And so, with that I’m going to turn it over to Steve Tomberlin who is going to talk about our development.
Thank you Bob. Just to check on the agenda, I’m going to spend about an hour talking about development and then we’re going take a break. And then John is going to get up for about an hour and talk about strategic growth. So, if you would need to take a quick break now, that’s going to be another hour before we take a big break.
I’m going to start in Texas, and just jump right in to an overview of where our acreage is based on Phase. The majority of our acreage is in McMullen County where we are in both the oil and condensate window where we have all of our activity plus we do in South AWP have some dry gas that we’re not drilling.
We also have Olmos development here, the Olmos phase doesn’t go exactly like the Eagle Ford phase, so actually when we show the Olmos map, it’s kind of an East-West in terms of going from gas in the East to oil in the West.
As we get to LaSalle County and Artesia Wells, where we’ve had lot of activity this past year. We’re in the very liquid rich condensate in the oil window. And then lastly but not least we have our web county, dry gas area. We’re only drilling two wells there this year to do some down-spacing test because it’s the only area that we haven’t down-spaced yet.
If you’ll remember, the last year we were – we talked about it in terms of we were fortunate that we could earn acreage there on 640 acre spacing, all of that acreage is earned, it’s HBP. But at some point when gas prices get to the right point, we’ll be back over there looking at Fasken.
As far as an overview, the things that are very, very important, of course we’re focusing on liquids. The margins are improving, I’m going to show you some details about the improving IPs and EURs, and very pleased with that and actually a little bit surprised as how well the wells have been coming online.
And then also lastly I want to make sure everybody knows we do have firm transportation and secondary connections in all these fields which keeps us from having any significant market interruptions.
For the next three years, here is a scenario of our work program. As you can see, all the 2% of our drilling will be in the liquids rich windows, almost all of that in Northern McMullen and in throughout LaSalle County and again the two wells that we’re currently drilling at Fasken that tested down-spacing.
This is a slide that we’ve used in the last couple of the Analyst Days to kind of tell us where we are in the Phase of development for our assets. So, if you dive back to 2009, in all these six areas, we really were in the evaluation and data capture phase. So we’re doing a lot of pilot holes, we’re taking a lot of course, we’re drilling some pretty restricted lateral links about 3,000 feet, but all that work has really come and helped us in 2012.
Since then, as we move into 2012, the different areas scattered about based on quality of the rock, based on drilling and completion cost, and based a lot on whether it was liquid rich or dry gas. So South AWP in the Eagle Ford was one that was left behind. If you remember we had a JV with PetroHawk covering a lot of that acreage. The northern part of that acreage was condensate rich or it is condensate rich but a lot of it to the South was dry gas. So that’s really falling behind. We haven’t drilled a well in any of that stuff for almost two years now. So it’s just sitting there still in the evaluation and data capture.
In North AWP, in McMullen County, we’re continuing to say we’re in the appraise and efficiency capture mainly because what we’re going to show you with our targeting and how we’re targeting the Eagle Ford and we’ve refined that target, we now feel like when we have the right target. And so it will be able to move into development and optimization capture phase, you’re pretty quick.
As I said earlier Fasken was drilled up back in 2009 and 2010. It really is getting close to the manufacturing stage, obviously we won’t go into that stage until we hit the right gas prices. But when the gas prices do hit the right level that’s the place where we’re going to get some really excellent returns.
SMR which is our northern most acreage in McMullen County, we’re still drilling a couple of wells to earn that acreage but we’re drilling up wells there that we feel like that were in a place when we were ready to go ahead and go into the manufacturing phase.
And that shows us where we are today. And with the right funding, you could see us being in Artesia and SMR and probably very quickly into North AWP getting into the manufacturing phase.
Let’s talk some about infrastructure. We have spent quite a bit of money since 2009 on getting the infrastructure in place. We feel like we’ve got a vast majority of it in place now that as we drill, we’re putting less and less money into facilities. We’ve got 160 miles of pipelines serving 20 tank batteries, almost 16,000 horsepower in compression with $80 million in throughput. We have 17 frac water ponds across the entire leasehold which gives us a huge storage capacity for our fracking operations. Those frac ponds are sourced by 14 water supply wells, so we don’t have any problem with getting water for our fracs.
And because we are handling so much water out there you want to do that efficiently. And right now we are finishing up a project where we’ll have 10,000 barrels a day of water gathering in disposal capacity, which will help us in 2013 lower our lease operating expenses.
So, what does that look like in the different areas as far as the spin, from 2009 to 2012? As you could see it’s the continual ramp-up to the highest level being last year, where we spent about $65 million on facilities. As we look at 2013, because we’re on the down-hill slide of putting the infrastructure in place, we expect that to drop down to about 40. And as time goes on, that number will drop even further allowing us to put more – a bigger percentage of our money into the actual drilling of the wells.
Bob spent a lot of time talking about drilling costs and completion costs and parameters and non-productive time. I wanted to just sum it up and show you where we are on actual well costs. 2012 numbers there were the numbers that we put forth this time last year at this meeting. Right now, currently and these are actual wells that have been drilled recently. You can see across the board we’ve dropped those costs from about 10% if you do some averaging through those six areas.
Right now, you can see we’re down in $6.9 to $7.9 and that’s drilled complete location hook-up that’s everything. And we’re actually achieving the lower numbers right now as Bob said, as our efficiencies continue, as the supply market changes a little bit with our vendors, we expect to be on that low end and probably improve on that as the year goes on. So, hopefully next year we’ll have a 2014 affair that shows even lower cost.
All right, this is the next four five slides that I want to spend the most time on. And this is something that has been real key to specially the second half of 2012, in our understanding of the Eagle Ford and how you have to drill this Eagle Ford.
I talked earlier about the fact that we spent a lot of time and we spent quite a bit of money early on when we went out here drilling pilot holes, taking cores, we did a lot of 3D seismic and that is starting to reap a lot of benefits right now.
With respect to the 3D seismic, the thing on this slide and we’re on slide 76, that’s important is the second line down, we have 3D seismic coverage over 80% of our acreage. The only place that we don’t have 3D seismic coverage is out in the dry gas area in Web County, of course if we ever – when we go and start to develop that we will get 3D because we feel like we have to have it everywhere to be effective in developing these shales.
So, let me spend some time on this. What we’ve got here is a log example, and if you can’t see it, this is the Austin Chalk and then this is what we call our lower Eagle Ford section. This is about 150-foot in vertical depths. So when you move over here, you got porosity, over here you’ve got some resistivity in here and then what’s more important as you go out here and look at the rock, and you start to look at photo micro-graphs, this area in here which is about 60-foot window is the place where you have the highest TOC or Total Organic Content so that’s where most of the hydrocarbons are. A lot of those hydrocarbons are associated with a lot of these little fossils in here you also, that’s where because of the fossils you have the best porosity so it’s definitely the place where you have the most hydrocarbons.
And so what we started to do is we started to say, well, maybe we shouldn’t be targeting this entire enterable and we should start to target a smaller refine window. The thought being when we first started drilling out here and this is one of the early wells that we drilled is that our target window was this 150-foot entire lower Eagle Ford. This is an actual well that was drilled so as we were steering the well, the thought was – we’re going to have to stay within this 150-foot window.
What we didn’t realize at that point conventionally we thought that that frac no matter where you put it in this 150-foot interval would grow up and grow down and cover all this effectively.
What we found as we started targeting the brittle zone, this was the same well, we had to do it over again today this is where we would do it. What we found is that you really have to be – have the well bore actually in this target window to get an effective frac on that brittle zone.
So where does that put us now? This is a very recent well that we drilled and you can see, here is the actual pass and we actually stayed in this much smaller 60-foot window. The other thing on this slide that is of note is you’ll see you got a red color here. What Bob had talked earlier about that this was a seismic inversion anomaly, essentially in that brittle zone where you have the organic content, you got the density change from the rest of the Eagle Ford. When you have a density change, then you’ll have a change in the inversion profile, so not only are we targeting this 60-foot window but we’re also trying to stay in this red zone.
So, what does that mean? This is a slide that Terry showed earlier and this is actually in the oil window in McMullen County. So, here in red you got the original wells that we drilled in that area, so this comprises 13 wells in the background you can see the individual wells but this is an average of those 13 wells.
In 2012, with the refine target window, here is the profile of seven wells that have been drilled. So you can see and almost doubling in production over this 180-day window, something that’s not on here that I think is really key is in our press release today we mentioned several wells.
One of the wells that we mentioned was the PCQ7H. If you go back and look at all the post-mortems on all these wells and look at how well they were targeted in this refined zone, the PCQ7H is one that stands out that is in the zone the best If you were to plot PCQ7 because it’s not one of these seven wells because it hadn’t been online that long. The first 30 days of that well, it plots on this 1,200 barrel oil a day line. So that’s our target, if we can improve from here to here and then up to here that makes a huge difference on our margins down in South Texas.
Another key, down-spacing. As we started drilling here in Texas, we started with 160-acre spacing. We’re essentially 1,320 feet between wells. In 2012, early in the year, we did several pairs of wells that we went down to 660-foot between wells, that worked for us and I’ll show you some plots here in a minute. And then we decided well let’s take it little bit further. So we took a three-well package and a four-well package in the third and fourth quarter, it went down to 60-acre and 50-acre spacing. And so far although we only have several months of data, it looks pretty apparent that we’re going to be able to down-space down to at least this 440-foot to 500-foot distance between wells.
Later this year, we already talked about Fasken that’s going on, a 60-acre spacing test. And then very late in the third quarter, in McMullen County we’re going to go and try to go all the way down to 40, so very important for our portfolio.
Here are some of the plots, the plot on the left is the Cardin area which is in Artesia or LaSalle. The red curve is the 80-acre spacing so that’s this over the first six months of production. The yellow curve is the offset wells that were at 160-acre spacing. So you can see throughout that profile no degradation in performance, as a matter of fact a lot of people would say, you’ve actually had some improved performance.
We then said, let’s go from 80 to 60, here is the Bats area, this is an area where we drilled three wells together. This is the 60-acre spacing in the red. This is the 80-acre spacing in the yellow. Early on we didn’t open the Bats wells up as much as we did other wells like you’ve seen throughout the industry people have gone to where they are going to more restricted chokes. So as we’ve developed our area down here we’ve done the same thing. So, a lot of these wells were probably opened up to 20-60 force chokes or a little bit higher. Now most of our chokes we are holding them to about 14 or 16 early on.
Skipping over to McMullen, the same type curves, on the left hand side the SMR area. As you can see the red a little bit better so 80-acre spacing, the profile looks a little bit better than 160. And then as you go from down to 50-acre spacing, you see a profile that’s pretty much the same up in through here. It looks like the wells are falling off, that’s actually not true. The wells actually are choked back there because they came in so well they overwhelmed the tank battery there and we have to make sure that we’re flowing other wells that are in that system but these are very, very strong wells. Yeah.
Yeah, we actually picked lateral links, they are maybe 100-foot or 200-foot off but it’s the close as we could get.
Okay, so what does that mean in terms of locations and upside? You can see there through 2012 we’ve drilled about 100 wells throughout the Eagle Ford and the Olmos and in the liquid area. You can see the remaining locations and you can also see that we’ve got over 300 million barrels of potential there. And Bob showed a number earlier of 244 that was specifically for the Eagle Ford. This also includes the Olmos.
Okay. You’re going to see this format throughout the presentation, I’ve got a couple of them or I’ve got three of them and John’s going to have a couple of them. And what we did is, we went in and looked at different scenarios. This is for our LaSalle acreage, and this – the premise behind this would be that we take a three-rig program and put it out there and continue to drill until we had all the locations drilled up.
We got about 13,000 acres there, 154 million barrels of resource. The position has definitely been derisked by Swift and a lot of people who offset us. And again, we have the takeaway capacity that we need to make sure that we can flow the hydrocarbons.
In this area, if you took a composite average, it’s about 50-50 on liquids and gas. I’ll show you a more detailed land-map here. We actually are concentrating our efforts up in the Northern part of this acreage because the ratio of liquids to gas in the Northern part gets up to about 70% liquids.
And then you can see a scenario profile, it would get you up at five years out to almost up to 40,000 barrels a day equivalent so some pretty large numbers.
Here is an acreage map. The blue wells are the wells that we have drilled in through here. The thing that I was talking about earlier in the Eagle Ford, you see this a lot across Eagle Ford. The richness of the stream changes very, very quickly. So, as you drill up in this area, and turn it to the Northern part of this lease over here, you probably are going to get about 3.3 bcf and about 250,000 barrels of oil.
You can move just a short distance from these wells to these wells down here and these wells are probably 3.5 bcf and closer to 70,000 to 100,000 barrels of liquid. So all of it, good, rich, value stuff but it changes very, very, very quickly.
These are the same map again with some IPs, pretty consistent on the IPs. Thing that it’s here in pink that surprised us a little bit is these – what we call the best three-pack. Those are the 60-acre spacing wells that we drilled. As you can see, if you look at those IPs of around 1,500 barrel oil equivalent that surprised us a little bit. It’s a good surprise and we hope as we continue to drill especially up in this area that will have those kinds of IPs.
Okay, this is another display that you’re going to see several times, so let me spend some time on it early on. What we’ve got here in yellow is the pre-2012 average of all the wells that we drilled in LaSalle County over the first year period of time. So, you can follow it and you can see relatively consistent. What we did then is we took the wells that we drilled in 2012 with the more refined target and said, let’s see what the performance has been over the same first year time period.
So, you can see, by and large the red curve is above the yellow curve. What we then did is do the model adjustment that we talked about – so now this green recent performance line here matches more to the 2012 average. And that’s where we went from an EUR of 950,000 barrel oil equivalent up to a little over 1,000.
This is just a composite type curve of what goes into the economics. It also has the different streams, the NGO yields and of course our drilling and completion cost are down under $7 million.
So, what does that mean for PV10 and right of return for an individual well in this area? And this is a different flat pricing so you can see we go from on the left hand side, $3.50 an M and $70 a barrel up to the right hand side $5 an M and $100 per barrel. Right now we all realized that we’re probably somewhere between these two if you looked at its strip prices going forward. But all across this gamete that $6.9 million well cost you’ve got returns anywhere from 31% up to 78%.
So, if you wanted to look at the cash flow for a three-rig scenario, that’s what we have here. In the light blue is the operating cash flow coming from the area. In the dark blue is the capital that you would have to spend over the first six years to drill this up. And you can see it’s about 36 wells a year for about five years and then in the six years it’s only remaining four wells.
Down here, if you wanted to try to recreate this, this is the price deck we used out for the first 11 years. The net cum cash flow is the pink line. So you can see over this 19-year period that you get up to about $3 billion net cash flow. That doesn’t mean the cash flow stops at that point, as you can see still out into year 18, you got positive cash flow. We just have to cut it off because it wouldn’t all fit on the slide.
So, what does that mean in terms of reserves? We talked that there is 154 million barrels of net resource. Over that seven year period, you’d have to spend $1.2 billion to develop it, almost $5 billion of total cash flow and then what does that mean in PV10, it comes out to be four in the LaSalle area, $1.5 billion if you went out there and drilled it up with a 3-rig program.
Okay, now I’m going to shift over to McMullen County and talk about the same type of scenario for the Eagle Ford and the Olmos liquid area. So, we’ve got about 21,000 net acres in the oil and condensate window of the Eagle Ford. We’ve got about the same in the oil and condensate window of the Olmos. This is a 156 million barrels of recoverable resource. We’ve got 309 drilling locations and again we have strong takeaway capacity there, we got about 9 million a day.
The production profile what it would look like would be little more than half liquids, 30,000 barrels a day at your peak rate which would be nine years out.
What does the acreage look like this is for the Eagle Ford? So, you can see a lot of the wells that we’ve been – this is SMR, this is all the Northwest AWP stuff. And then we actually have drilled down into this area. Once you get further South down here you get out of the liquid window. So this is the main area that we’ll be focusing on the 21,000 acres.
So, let’s go to the pre-2012 and 2012 performance. Here in the McMullen oil, same curves, yellow curve is the pre-2012 well. The red curve is – our 2012 wells and so you can see the red line is above the yellow line pretty well throughout that time period. So, we’ve actually raised our EURs in this area from 381 this time last year to 453.
Shifting to Olmos, and remember Olmos doesn’t follow the same trend in terms of phase that the Eagle Ford does. So we’ve been drilling Olmos throughout the area and it’s more on an east-west trend. So, a few wells up here in the channel that are oil wells and SMR. Then here is the bulk of the Olmos drilling we’ve been doing. A lot of this in here was actually rich gas drilling, very prolific wells, we average about 6 bcf but they’re only about 28% liquids.
As you move toward the west and toward the west up here and actually there is some acreage that’s shown on the map, and you move to the Southwest down here, you very quickly go from rich gas and to condensate and oil. As a matter of fact, the last well we drilled in this area came online at about 750 barrels of oil per day. So, we’re moving west with the Olmos and we’re staying up north in the Eagle Ford.
So, the Olmos type curves, the first one is Olmos oil, same scenario here. Again the 2012 wells are outperforming. The pre-2012 that’s we’ve upped the EURs by about 100,000 barrels.
And then this is the condensate, as you look at those two curves early on, the pre-2012 wells looked a little better as you got to about 200 to 300 days of production, it looks like the 2012 wells were little bit better so on this one, we said, what – we really can’t see a change so we haven’t changed our EUR forecast for these type wells.
Since in this area we have four type curves that we use, what we’re showing here on this curve is just one of the most predominant type curves which is the Eagle Ford oil which would be the step up in Northwest AWP. This stuff as you can see is about 78% liquids. And the drill costs are a little bit higher up here, a little more difficult to steer the wells in this area because there is a little more undulation in the formation whereas in LaSalle the formation is very quiet and it’s very smooth. So, when you get in it, it’s easy to stay in that 60-foot window, little bit more difficult here so it costs us a little more drilling to complete these wells.
Economics, same flat price decks. Pretty close in comparison to LaSalle, even though the well costs are little bit higher here because it’s little more liquids in this area. Your right to return range from 25% up to 78% so right now as we drill these wells, we’re probably in the 50% rate of return arena.
Cash flow, more wells to drill here so it’s going to take you almost 10 years to drill this out with a three-year program. You can see over the first 18 years you’ve got cumulative cash flow in excess of $3 billion but you’re going to have to obviously spend some money for these 309 wells and that money would be $2.4 billion in CapEx, total operating cash flow a little less than $7 billion, but you get almost $1.5 billion PV10.
Okay, I’m going to shift in to Louisiana. First place, we’re going to talk about is our legacy asset of Lake Washington and Beta Shane. Again, a locator slide here. So, what’s our focus in this area? Terry and Bob talked about the really great margins here and the cash flow that’s generated from the Louisiana properties which is about 40% of the company’s revenue. A lot of that has to deal with the fact that you’re getting HLS and LLS prices but this is still a very key area for us.
We haven’t spent as much money the last two to three years in this area as we conditionally do. But that as strategically done because we needed to spend money in South Texas to earn the acreage that we’ve talked about already in – the potential.
As we move into the future we’re looking deeper in Lake Washington and there is two ways we’re looking deeper. We looked down to the LICC level which was what the Newport discovery was. And then John is going to talk about the sub-salt that goes down to about 25,000 foot level.
In the meantime we’re producing about 100 wells out there, we do a lot of optimization on a day to day basis, a lot of the money that we’ve been spending has been on development drilling and rig re-completes. Out there you got paid from 1,500 down to 13,000 foot so there is lot of zones that you can hit with an individual well bore. That activity of doing those re-completes really helps us to sustain production.
On the left hand side here you can just see, normally we do about 15 rig re-completes a year, they cost about $1 million apiece. We do about 40 sliding sleeves so what that means is as we originally complete these wells, we may perforate up to three zones and have each of those three zones isolated. And then you can go in there with wire line and actually close off a zone and open another one up. So, something that usually costs you $8,000 to $10,000 but it’s been very key in this field.
Number of gas lift optimizations and then some new drilling activity last year. Here in the dark green it’s maybe a little bit hard to see is your – what we call the base production. So that means that your PDP, that is all your stimulations and gas lifts that’s all your sliding sleeves and that’s all your rig re-completes added together.
The lighter green is actually the new wells that we brought on. For most of the year, and this is gross BOE per day, we were pretty flat at about 8,000 barrels a day. We then had hurricane Isaac. When you have a hurricane like that, it sometimes takes you a while to get everything back running. So what happened to us is that we actually will run in a rig through this period, brought on some wells here and then we let the rig go. Well, we already heard in our earnings call, back in February, we had an instance where four wells watered out pretty suddenly.
A couple of those wells were big Newport wells. And if you remember Newport it was discovered back in 2005 and at one point, over a two-year period, it had maxed at about 9,000 barrels a day of production. Right now, because of the event that happened here, those same wells in Newport are only producing about 500 barrels a day. So, it’s unfortunate that those things happen but what we have now, I believe is a more stable production base where you’re producing out of 100 wells and you don’t have a lot of – just a few wells dominating that production profile.
So, what’s happened since the fourth quarter, so this is the drop – same curve except now this is January of 2012, up until today or this was actually a couple of days ago. So, you can see kind of flat around 8,000 brought a couple of big wells on, had some wells water out. And then kind of the third week of December, things really started to flatten out. As a matter of fact, we didn’t have hardly, we didn’t have any capital activity in the field at that time.
We finally brought the rig back out there, we got the re-completion online and we’ve actually bumped it back up to 7,000 barrels a day. What we forecast for the rest of the year with our activity is we’re going to want to stay flat at around 6,500 to 7,000 barrels of equivalent. Very important, very important cash flow for us with way the things have flattened over here in the first quarter, I’m very optimistic that we’re going to be able to do that. And we’re actually going to be doing that with probably only spending $50 million to $60 million in capital.
This is just another depiction of 2013. And this tells you the base and then the new well contribution that we expect to come in and this is just the actual for the first three months.
Okay, let’s look at it from a historical stuff for our capital spend down here. This first slide, I’m having three slides are all in the same format. This is for our rig re-completion, track record. You can see we do somewhere between 10 and 20 a year. One of the things that you have to keep in mind here at the bottom it says, we have 55 in inventory. Some people have said, if this is so good why don’t you just go do those 55. Well, remember we got 100 producing wells out there, those 55 are zones that are up the hole in these producing wells. So we can’t go up the hole and access that re-complete until the zone that is producing in the well bore actually gets down to 20 to 25 barrels a day and then it’s worthwhile to go up and get the next zone.
Development cost here has been a little under $13 a barrel. When you look at something that’s close to brand pricing at $110 a barrel come in, in revenue obviously you’d want to do these as quick as you could. It generates a lot of revenue, pays out very quickly.
The development drilling which, would essentially be the PUDs that we have on the books. We’ve been doing probably averaging about 6 or 7 a year, not as good as the re-completes in terms of a development cost. But it still is under $20 a barrel, still very, very high margin stuff.
And kind of see, as we came out of the financial crisis of 2009, our drilling cost look really low that’s because we were drilling very, very shallow. We had pulled back on capital, we’re drilling wells that were anywhere from 2,000 foot to maybe $3,500 foot as time has gone on. We actually – you can see the well cost coming up because we’re now going deeper into that development portfolio down to about 6,000 to 8,000 feet.
The third area that I want to spend the most time on is what we call extension drilling. So, this is deeper drilling down to the LICC series which for the most part is down 12,000 to 13,500 feet. Again, coming off the financial crisis, we weren’t putting a lot of money into this arena. We started drilling some wells in 2011 and 2012. Obviously these wells are going to cost more – around $10 million to drill and complete. But they also have a very attractive refining development cost at under $12 a barrel.
So, what are we going to be doing in the future? We always will be doing the re-completes, we’ll always be doing the PUD drilling when it’s appropriate. But what we really want to focus in on is our hopper – deeper opportunities. This is a depiction of the opportunities we have and these are actual prospect names. There is about 60 of them that are in here. So, as we look at 2013, we got about six more prospects that we feel have gone through this hopper and are now ready to be designed and put in the drilling schedule.
As you go back you can see each year, we’re targeting about six. As you go back even further, you’ve got 30 to 40. Now, as these 30 to 40 go through this, not all of them make it. So, you’re always having to replenish this but a pretty robust portfolio.
So, where is that portfolio? This is a – Lake Washington Salt Dome, up in the northern area, and LICC series almost 60 million barrels of production. We then in 2004 came in and found Newport with 9 million barrels of production. Then here in Jelly Bowl, there has been about 25 million. This is an area that we talked about last year because we drilled the Jelly Bowl well. It’s still flowing, it’s a very good well still making about 500 barrels a day.
And then also important is that with your PUD, either today or maybe late last night a follow-up to the Jelly Bowl, so this is the original Jelly Bowl well. We’re coming in and drilling this fall block. Our plans are to continue to move in this direction. As long as we’re hitting hydrocarbons we’ll continue to drill those fall blocks.
To the little bit north, and to the west of Jelly Bowl so here is the well we’re drilling right now is in this fall block. You got some very large fall blocks and what we call the South flank. We’re very high on this area. We aren’t drilling it currently or don’t have plans to drill it in 2013, the reason being is we need some additional seismic out here to be able to really image where we want to put these wells.
John’s going to talk about seismic for the area in relation to the deep prospect but as we plan that seismic program we’ll plan to try and get this area first so that we can drill hopefully in 2014 on the south flank.
West flank, this is around where we had both the Newport discovery and then a smaller discovery called Hershey. We’ve got a number of fall blocks here, we also have a bigger structure that’s about 450 acres, that’s about 2,000 feet below this level. So, we think the potential in this area, it could be up to 40 million barrels. Again very nice high quality sands throughout the area.
In Beta Shane, we also have some deep LICC potential there. In Beta Shane, you get some gas coming in. It’s probably about 50% liquids over here. So, it’s not on our radar screen as much as Lake Washington is. But down especially in the Southeast flank there are some really big potential there.
So, on a timeline when would we expect to be accessing this potential? Development wells, we’re continually doing that. For the South flank that’s in purple we hope to get the seismic and be able to Spud a well either in late 2014 or early 2015 as we just talked about the Jelly Bowl Spud within the last 12 hours.
The west flank, we think will be ready to drill in that area either late this year or early in 2014. And then Beta Shane is kind of the wildcard if you guys can predict what prices are going to be like, I could hone in on when we drill those opportunities. But for now we’ve said it’s probably going to be out to probably 2015 before we do that.
So, in summary on Southeast Louisiana. It’s been a great asset and continues to be a great asset for Swift. We’ve got a very good track record. We saw that the development cost range from about $10 to $20 a barrel. Over 80% oil, we get the Gulf Coast premium. And it’s really to us as a gift that keeps on giving. And we’re going to continue to invest in it. And we’re looking to invest in it even at higher levels as we move into the deeper horizons especially in the sub-salt.
Okay. I’m going to spend a little time on Central Louisiana. I’m going to talk about the Burr Ferry and Masters Creek area concentrating mainly on Burr Ferry because that’s where we have our JV partnership that we’re active drilling Austin Chalk wells. I won’t be talking about South Bearhead Creek because John’s going to talk about it and what we’ve got going on in the Wilcox.
In Burr Ferry and Masters Creek, we’ve got a lot of acreage over 200,000 net acres. In that there is about 88,000 Swift minerals of which about 21,000 is included into our JV with Anadarko petroleum.
So, what does it look like for Burr Ferry in the future within the 2 AAMIs we have 36 more wells to drill. These are 1,500 acre units. It’s about two thirds liquids, 10 million to 16 million barrels of remaining resource potential in this area, also it does get the benefits of the Gulf Coast pricing.
So, focusing in on what we’ve done so far with Anadarko. You can see the wells come online at anywhere from 3 million a day and 1,000 barrels of oil a day up to 10 million a day and close to 1,000 of oil a day so very, very strong IPs in this area.
Here is a summary of our results since we started this with Anadarko. One of the things that I’m going to talk about here in a minute is the completion technique in these Chalk wells which we think is absolutely critical.
When you look at the wells that have been really good wells, the top left hand box there, you can see out there on the completion verbiage that the first two were five stage completions.
What that means is, is that you actually are running in the hole with what we call swell packers. So, as you run this pipe in the whole, as you leave it down there in that environment, those rubber elements will swell and seal off against the formation phase. What we then are able to do is go in, in each of these areas and stimulate this section of rock, close that off, stimulate this section of rock, again, again, again.
Why this is key is as you’re drilling the Chalk you hit a cluster of fractures. Those hydrocarbons and water in those fractures is going to really surge into that well bore, which means you have to have a tight control on your mud-way and make sure that you keep that well under control. When you have to make it tripped a bit out of the hole and change it out, that means you have to kill that well with heavy, heavy mud, lots of times up to 19 pound. When that happens, as you’re tripping in and out of the hole, you will start to lose that mud into the fractures.
As you look at the temperature in this area, it’s well over 300 degrees. That mud goes into the fractures when you open the well up to flow, guess what, the mud comes back with the hydrocarbons. You got to get where you make that mud less viscous or less thick because as it comes back in its natural state, then you’re liable to have it thicken up and actually dehydrate. And when it dehydrates it becomes almost a rock. So, you don’t want that to happen.
To prevent that from happening, you got to go in with this acid and this water that has a bunch of solvents in it, push that mud either away from your well bore or at least thin it up so that when you produce it back it’s not coming back as a thick slurry, it’s more of a like a diet coke instead of a thick mud. If you do that then the well will clean up and you’ll have a good well for a long period of time. If you don’t – about 50% of the time, you’re going to have that mud thickening up on you actually dehydrate and then you got a big problem.
So, what does that mean in terms of well performance? These are all the wells that Anadarko has drilled to date. As you can see there is a lot of wells they have a really great profile. This is one year, two year, three years, and then you have several wells that don’t have such a great profile. Well, a couple of these wells we had mechanical problems in, another one was gone out of the zone of the fairway zone, it didn’t hit as many fractures. But the important point here is that these – this yellow, that’s highlighted in this pink that’s highlighted in bold are the two wells that we’ve had the swell packers in. They had been two of our best wells, it’s a little misleading, these are our first two wells and actually these wells were opened up to about 36, 64s choke where these were held back. And I actually think that these two wells are going to be the best wells that we have out there, the ones that have the swell packers in it.
So, it’s something that we’re constantly working on and we think is the key to this joint venture and getting more out of it, but it’s also key to anything that we would do in Masters Creek in the Austin Chalk.
I’m going to go back to the performance slide and just mention, we actually went in and wanted to see what the economics were to date for these wells. And what we did is we actually went back and looked at the actual cost and then we looked at the revenue that’s come in. This program is on the positive side of cash flow. And then we looked at the forecast for the wells that are producing instead what’s the cradle to grave economics. So we’ve spent our share – about $43 million, we’re going to have almost a 200% rate of return. And then we got a PV10 of about $47 million.
In 2013, we planned to drill three to four more wells. We got the AFEs coming in from Anadarko right now. We see we got a well here in the cluster of the good wells and then we’ve got AMI2 wells that we’re going to follow up with later this year.
So, what does that mean for a possible scenario? I’ve already talked about the acres and the resource potential and the fact that this is about two thirds liquids. We expect over the next few years if we’re drilling about six wells a year, that we peak out at about 4,000 barrels a day net. Here is a typical well profile, now these wells are relatively expensive. As time has gone on, the costs have come down. But right now a well drilled complete, equipped, with the salt water disposal well is about $11 million.
Economics, very strong – remember we have some royalty interest in some of these wells, so that really helps the rate of return. Cash flow gets up to almost $400 million. You’re going to be drilling five to six wells a year over a six year period. The net share of those wells to us is between $25 million and $30 million. So, here is the summary of the potential, about 14 million barrels of potential. CapEx, $230 million over that time period, PV10 value $271 million.
Summary of the development side of the business, we’ve got a lot of liquid opportunities, lot of it has premium Gulf Coast pricing so it’s very good margins. We’re not drilling any gas right now but we have in our hip pocket the Web County HBP acreage which is about a TCF in potential. If you wouldn’t spend a lot of time doing any profiles for you for Fasken, but I did want to throw in one note here on the economics, if prices were at $4.50 an M, these type wells which are about 10 bcf and $7.5 million to drill and complete is a 139% rate of return, and a 10-month payout. So, it’s something that as gas prices hopefully continue to rise that we’ll have to think about in terms of executing some wells out there.
So, the total Texas between LaSalle Eagle Ford and McMullen, Eagle Ford and Olmos in the liquid areas is 310 million barrels of resource potential. And Web County in the dry gas area its 186 million barrels. If you look at Louisiana, Burr Ferry, 10 million to 16 million barrels of resource potential, rig re-completes about 3 to 6, development opportunities in Lake Washington 6 to 10, and then if you look at the extension wells or the LI to CC series in Lake Washington Beta Shane, if you added those last two, two numbers together you’d get something be a 11 to 170. So, still a lot of running room, lot of great things to do in both Texas and Louisiana.
Okay, it’s time for a break.
Yeah, let’s take about 10 minutes. Be back in here for the next portion of the presentation. I really appreciate the help with that so far, thanks.
Okay, if we could take our seats please. I’d like to restart the program here, realize everybody is having a great time with the assorted nut mix and dried fruits but plenty more Investor Day action in here in the main ballroom. Only 347 more slides to go, so if we can just find our seats. (Inaudible)
All right, a new record for the cattle call there, thank you so much for your help. Now that everybody is back in there room here, we will begin the second half of the presentation here. It’s a pleasure to introduce our VP of Geosciences, great man, a very intelligent man and very experienced in many of the things he’ll be talking about here, John Branca.
Thank you Paul. Is that too loud? This is okay. Yes, this morning I’m going to talk to you about some of our strategic growth opportunities. Last night, a lot of you were asking a lot of questions about some of the things that we have in our very near future. And I’ll be able elaborate much more right now.
First, I’m going to introduce strategic growth and the initiatives then I’m going to talk about three opportunities that we’re working on and they have a variety of risk and a variety of rewards that I’ll share with you. They include the South Bearhead Creek and Wilcox horizontal program, Southwest Colorado Niobrara horizontal program and a Lake Washington sub-salt program.
First, I want to talk about the drivers for a proactive strategic growth program. And really this is to broaden our portfolio to improve the certainty of economic production, revenue realization and growth. This is really going to be a compliment to the things that Steve showed you earlier are ongoing development programs that being the Eagle Ford Shale and the tight gas sands, the Louisiana Austin Chalk carbonates and the Lake Washington Basin Miocene Conventional Reservoirs.
We’ll continue to build and test oily plays and upgrade the production and increase our reserves value. We’re also going to continue to differ our gas development programs until the commodity prices improve.
Now, to as we embark on this strategic growth program, we’re going to dedicate 5% to 10% of our capital budget each year on opportunities and strategic growth initiatives. We’ll focus on two to three new plays each year to ensure a sufficient inventory for the strategic growth for 2015 and beyond. This is going to include risk to diversification and funding.
These resource plays as you will know yield great solid production growth and great reserves growth but they consume a lot of capital. And so, joint venture funding is something that was mentioned earlier and that something that we’ll be considering for some and many of these projects.
We’re also adding high risk, high return opportunities to the portfolio, we think these are very important to add. But these opportunities also need a joint venture partner so that we can share the risk and we can also help in the funding. Partners are a great source of peer review. They – when you work with them they ask you a lot of questions and make you think the things that you might not of considering so they’ll help in the overall risk management of these higher risk opportunities.
Now, I’m going to talk to you about South Bearhead Creek and our Wilcox program. Here is a map of location map, South Bearhead Creek sits here in Louisiana and Plaquemines Parish right near the Texas Burr. Here is a structure map on the upper Wilcox in South Bearhead Creek field. I want to point right here to this blue line, this is our Dolby H1 Wilcox well, it’s a horizontal well that we’re presently drilling.
We’re in the lateral section, the VP of drilling just informed that we’re about 1,500 feet from the end of the lateral, we made a 1,000 feet yesterday which is just incredible. And we’re drilling this out lateral here and we’re going to be testing that right after we get it completed. So that’s happening right now as we speak and I’m going to tell you quite a bit more about this well.
But South Bearhead Creek field is a field that we’ve drilled quite a few vertical wells in and so we know a lot about it. And these green dots here are oil wells that have been drilled in this field.
This map is a map of the activity in the area and our acreage position. And I’ll first will highlight the yellow, this is our acreage, our units in South Bearhead Creek field, here is the Dolby number one well which sits here. And then these squares and triangles and starts are showing activity of offset operators. So offset operators are out here drilling and I’ll speak to a couple of the wells that they’ve been drilling. So, very active area and we’re drilling this well as we speak.
We, Steve talked to you about the Eagle Ford wells and our evaluation programs. And although we drilled quite a few wells out here, we wanted to drill a pilot hole in the first horizontal well and this is the pilot hole we drilled in the Dolby James 1H well. And we drilled a straight hole down to the base of the upper Wilcox and we’ve allowed it, we’re taking, where we took rotary cores in this well to get the evaluation.
What we will do as we go into the development program, we use this information very much likely used in the Eagle Ford to find the best zones, target the best horizons and get the best production out of these wells. I don’t have those pictures to show you of the core because they are being analyzed and we’ll have that in a subsequent presentation. But we do have the cuttings that we’ve looked at.
But before we go to the cuttings I’ll show you the logs. Here are the paid horizons, these red flags here are all petro-physically calculated pay and this is pay we knew about in the old, and pay we anticipated. So, the well came out just as anticipated. We’re targeting our lateral in this upper Wilcox B zone here.
Now, these same grains here in this photo my graphs correspond to these rises. And the reason I’m showing them to you is these are very quartz rich sands that’s really good, there is not much clay minerals in here. And there are siliceous mined which is a form of quartz. And so this rock is going to be extremely brittle, and it’s going to be very susceptible to multi stage fracking which is good. So these rocks will respond to fracking very, very well.
Now, here is a cartoon of what we’re trying to accomplish and also of the opportunity set. First when we speak to the well, here is the well that pilot wholly drilled and we drilled this pilot hole down to the base of the upper Wilcox interval. And we encountered the three Wilcox intervals a, b and c. We’re going to now, we’ve come back up, we took all of our information that well got the logs, we came back up for drilling in the lateral. So, we’re pretty close to the end of the lateral here. And here is a cross section, a cartoon showing what we’re trying to accomplish here in the B-zone.
Now, I want to point to the horizons. In South Bearhead Creek fields, we have identified and are producing from upper Wilcox, a, b, and c zones, but there is also lower Wilcox, a through f zones. But for the purposes of today, what we’re going to discuss, all of the economics and the resource potential that we discussed are going to be related to only three of these zones, a, b, upper and f lower. And they are highlighted here in yellow with reserve potentials from two to four to 10 million to 14 million barrels. And then the wells will take to exploit that. You can see that there is a lot of additional potential that we’ll exploit as we continue this program.
Here is a net pay map of the upper Wilcox B-zone, and here is our well that’s targeted here for six-section in this. To exploit this we’ll need to draw 19 horizontal wells to exploit the a and b zone in our development plan. And you can see those are the horizontal wells that are shown here as our development plan.
Now, we don’t have any history of horizontal wells in our field because this is our first. But we do have a lot of history in vertical wells. And the vertical wells in the B-zone, the average IP is 100 bills to 200 bills of oil per day. The average EUR for those same wells is 200,000 to 500,000 rolls of oil equivalent.
So, our horizontal wells, we’re going to drill a 5,000-foot lateral and we expect our initial production to be between five and 10 times that of the vertical or 500 to 2,000 barrels of oil per day. The EURs, we expect to be three to four times of vertical well or 600 to 2,000 or 2 million barrels of oil equivalent.
The offset operators have drilled a couple of horizontal wells and they have reported results to the industry. The reports are incomplete but this is what we have. The first well was drilled 2,200 feet horizontally, which is less than half of what we intend to do. And their IP was 1,190 barrels of oil per day and 197 barrels of natural gas liquids. And for four and half months their average was 650 barrels of oil per day, so very consistent with what we’re forecasting, and in fact we may be forecasting a little bit on the conservative side, considering we’re going to drill two and half times that lateral length.
Well number two is a 3,550 foot lateral, and they only report it an IP of 926 barrels of oils per day and that’s all the information that we have. This was the initial 14-day rate. But still within the range that we’re forecasting so we’re feeling pretty good about our vertical to horizontal multiples for these horizontal wells.
Now, these are similar to the slides Steve showed you. And we just want to show you what the resource potential is here for the upper and lower Wilcox a, b and the lower Wilcox f. So, only three of those nine zones that I showed you.
So, 20 million to 28 million barrels of oil equivalent, our acreage position, these are the two units we have in the upper and the lower. It will take 19 upper Wilcox wells and 12 lower Wilcox wells. And we’re drilling that well now, we’re going to evaluate that completely and test it this year. With the success of that next year, we’ll drill two upper Wilcox appraisal wells, appraising that field and then two lower Wilcox wells to evaluate that. And then the program will continue from 2015 to 2017 with 26 wells to exploit the remainder of the field.
Here is a scenario showing a production profile with that drilling program. And so, we get up to 12,000 barrels of oil equivalent per day, where the majority of this is oil, gas there is natural gas liquids in here which would be about 12% of the gas. So we’re a very oily in this and that’s one of the reasons we like this.
Here is a decline curve for the Upper Wilcox well, and these are using the rates that showed you before with an EUR of 650,000 barrels of oil. And they show 30-day test of 800 barrels of oil per day, the three to four time EUR average for vertical well would be IP of 5 to 10 times. And here shows a decline with some pretty solid production in early parts of the well.
So, success case in the a and b, these are the parameters that we’ve used, 800 barrels of oil per day, EUR 780,000 of oil equivalent. We put here a piece of that 100%, it’s a proven play. It’s proven oil well, we know the field very well. We’re just testing the horizontal multi-stage frac technology and a proven field.
At Wilcox we’re estimating at $11 million, with a 5,000-foot lateral. We drilled 19 wells, one this year, 18 through 2017 with a total resource potential with 10 million to 14 million barrels of oil equivalents. This will require a capital of $242 million, our return on investment is 3.58 IRR of the 116%. These will payout in two years and NPV of $280 million. Here this is a similar slide that Steve showed you, shows the sensitivity to oil price, these are flat decks. And so some pretty solid returns across the price deck scenarios.
So, this is the up zone, the lower Wilcox f and similar parameters. The f is over-pressured and it’s deeper so it’s going to have a higher IP. It will also have a higher ultimate recovery. And therefore the well cost will be higher as well take more casing to drill a little bit more difficult to drill. We have 12 opportunities, two wells next year, 10 wells through – additional wells through 2017 and the resources of 10 million to 14 million barrels of oil equivalents.
So, that will require a $176 million ROI of 4.22, IRR of 329%, payout in 15 months and the NPV of 333 million. So, for the whole program, 31 wells requiring $418 million ROI of 3.85, IRR of 183% and a payout in 25 months with NPV of 613 million.
And here is cash flow, you can see we’re drilling these wells and spending capital to drill those well. Here is the cash flow, creating total CapEx of $415 million for the resource of 28 million barrels of oil equivalent.
Now I want to talk to you about a new project for us in terms of preparing to drill. The Niobrara horizontal program, we’ve been working on this project for five years. Here is this map on the lower end of the slide shows Niobrara basins, this map up here shows our acreage position. There is a well, a horizontal well that’s being drilled by an offset operator here. We’ve amassed 70,000 gross acres in this play. Like I said, there is a test offset on horizontal well but no results published yet.
We plan a test later this year. There are horizontal tests going on in the San Juan Basin which sits down south of where we are. We’re also extending this play into some inter mountain basins to the north and we acquired 14,000 acres in those plays. And we’ll be watching federal re-sales this year and next.
This interval is – it’s called the (inaudible) it’s also equivalent to the Niobrara. There is multiple pay horizons in here throughout the interval. We’re focused on these two intervals right for the immediate future. But we think they are going to be productive. They are traceable laterally across the area. So across our acreage position and beyond these are very consistent horizons and we think anything that we can do will be repeatable.
The Niobrara actually outcrops to the north and there is this ridge here that’s been highly sampled and studied and it’s a great correlation to the wells, there is a lot of funds that they created, funding our crop and we correlate that into our area.
What I want to point out here is very high TOC in these rocks. TOC in these resource plays is very, very important and good. It’s also a very calcareous. And that’s also excellent because it makes these rocks susceptible to natural fractures and their fractured an RAI, they are also susceptible to fractures by hydraulic fracturing. And we can – we’ve mapped this high resistivity zone which is the best part of the rock, the high TOC and the porous rock.
What I’m going to show you now is a sub-regional map of the area. Our acreage position is here, here is where the rocky outcrops to the North. There is a ridge here called the hog back monetize negation to the San Juan Basin. Now the couple of points I want to make, why would people think about nitrous as gas. And it’s true there is nitrous gas but that’s mostly down here in the basin. We’re coming up, and as come up, the maturity like is pretty well established with the production. There are lot of wells, these wells highlighted for here are oil wells and we know that is very similar to place you see like the Eagle Ford where you go down in the basin, it’s gassy.
So, if you get down San Juan, absolutely these are all gas well, these red dots. But we’re focused on the oil part of the play. We have done so from the beginning.
We also have vertical wells that have produced in this area, I’ll tell you more about those later but there are three fields that are right and are first in our position here, the red massive field which has 29 vertical wells and that tune into 25,000 barrels of oil per well. And our Plaquemines field has seven wells in this particular rise in 97,000 barrels of oil in Invert fields goes, 231 wells.
Now there is also offset operators are now starting to explore in the area. And Red Willow has drilled a horizontal well here right on (inaudible) play, and Cana is operating in the basin, they’ve drilled a horizontal well as well as Bay-list. In fact and Cana just recently announced they’re going to have a two rig program out here and drill 27 wells this year. They’ve also announced the well with 300 barrels of oil per day, so they seem to like this play as well.
We’ve divided all plants and sub basins and these are areas of slightly different style but they’re all perspective. We’re going to drill our first well along with Monique line here and exploit this. Like I said, we’re up dip in the oil window, very high quality oil and we’re out of the dry gas in the San Juan Basin.
Here is a cross-section, now I just want to show you the rock out-crops here in the North, we come down and you can see, you can trace these horizons all the way across our perspective area here which is defined by these large faults that we think are enhancing the reservoir here and across here, you go down into the San Juan Basin you can see your drop pretty rapidly into the horizons here which still continue in a very good productive but they’re gassy.
So, let me highlight some activity. You may have heard about Williams test, they’ve drilled Mancos wells, they drilled a lot of vertical wells out here that were not very productive. But then they turned around and drilled a couple of horizontal wells and they’ve gotten 3 million cubic feet of gas per day, IP here and they produced almost 2 bcf in 25 months. So they proved the horizontal mono-stage frac technology in the San Juan, our ConocoPhillips has tested a well here, they got 9 million cubic feet of gas a day. And Cana has drilled this well here and they are – I just told you that they have their horizontal program that they’re two rig program that they’re going.
And there is some Cana activity here. So here is where we are, we’re on trend with this big oil play that’s running right in the basin and we’re in the midst of our proven oil.
I just want to show you a comparison, this play to other plays that you’ll recognize. Here is the Niobrara and the DJ basin, Bakken, the Eagle Ford, the Bone Spring World Camp and then our Niobrara and San Juan Basin. And here are the depth ranges from 5,000 to 11,000 feet, we’re in the 2,300 to 6,500 feet so we’re a bit shallower. Here are the thicknesses, we’re right on par with the thicknesses, a very large perspective area that we’ve captured a nice of.
Fractures are tend to be very important and we’re very excited about the fractures are locally abundant in our area and we’re going to capitalize on that. We have high TOC and the best rock in our area is 8% and we’re focusing on that high TOC and the high porosity of 11% here.
And so, these plays that I’m showing you are the oil plays and we’re consistent with a lot of really top oil plays in the industry and the US.
Now, we haven’t drilled a horizontal well, there are quite a few vertical wells that have been drilled. And I’ll go through that with you.
In Southwest Colorado, North New Mexico in our play area have five fields that acquired 27 million barrels of oil. There have been 350 vertical wells drilled in these fields and they have produced in the EUR average of 78,000 barrels of oil per well. And these wells were drilled in the 60s to the 90s.
In the San Juan, there have been 2,400 wells vertical wells drilled and they have culmed 84 million barrels and their EUR is in the average of 35,000 barrels oil per well. And they were also drilled to 60s through 90s.
There have been two horizontal wells drilled in the San Juan, I assume 10 culmed 1.2 million barrels. Now these wells were drilled in the 1990s which, in the 1990s we didn’t have multi-stage frac technologies so these are old technologies they are short laterals and only less than 2,000 feet and they culmed 123,000 barrels of oil equivalent per well.
So, we’re proposing 4,000 foot laterals and we expect to get 250,000 to 400,000 barrels of oil per well and we expect these wells to have 3.5 to 7 times the vertical well’s EUR and 2 to 2.3 horizontal EUR.
So, here is what success looks like. IP is going to be 360 bills to 560 bills of oil per day. Here is the EURs we’ve talked about. We’re saying that our first well is going to be 75% piece of this. It’s – we know that the oil is there, we know the rock is there, we’re going to drill a horizontal well and do a multi-stage frac and we’re going to see how it performs, that’s really the key to this.
The well costs here are for $6 million to $9 million, the first well we’re going to drill is going to be $9 million, we’re going to take significant amount of conventional core so we can do the kind of work that we do in other formations like the Eagle Ford for targeting sweet spots. We’re around full swing of logs, it’s also a test. Then we’re going to drill out and drill the lateral and test it.
This well cost for our development scenario here is $6 million. Now I have to tell you that offset operators have announced in the DJ basin their well cost of running drill and complete $3.5 million to $5 million, the DJ basin is deeper. And so we’re probably estimating a little high on our well cost and we’ll see these costs come down as we go into the development program. That’s what we’ve used in this scenario.
We have a total 860 well opportunities here. We’re drilling one this year and then from 2014 to 2053 in this scenario, we drill out the remaining 859 wells. Now, clearly that’s not the way we’re going to develop this but we’ve just done this for the scenario, if we really like this we’ll ramp up our activity levels.
The resource is 125 million to 200 million barrels and here this shows you some potential well spacing and we’ll be testing down-spacing as we develop. So, this is going to require $5 billion in capital to exploit this. The ROI is 3.11, IRR is 72%, payout 63 months and NPV of 2.8 billion.
Okay, now I want to talk to you about Lake Washington. And we’re going to talk about our sub-salt Miocene prospect. Lake Washington, it’s in the point shore Louisiana and the State Waters. Here is Mississippi Delaware, here is our Beta Shane field.
First I want to remind you, Lake Washington is a fabulous field. Steve talked to you about the exploitation and development we’re doing on the top of the dome. This field was discovered in 1931, it’s a giant field. 300 million barrels, a TC of gas have been produced from this field with 90 pay horizons in this field over 19,000 feet. We acquired it in 2001.
Here is a type log we put together on a number of logs to show pay intervals this is about 20 of the 90 pay intervals. But what’s important to note is this is Pliocene and Miocene and Pliocene sands up to 32% porosity, Darcy permeability, this is fantastic rock. And we’ve exploited this and it just keeps, keeps performing for us. But I’m going to show you why there is even greater potential below.
When we acquired the field there was no 3D seismic over the Lake Washington field. In fact, here is a 2D seismic line over the Lake Washington Dome. And what you can see here a little bit is some salt, we knew there was salt in there of course from drilling, here is the intervals that we were exploiting. And then you can see what might be a base of salt but it’s really kind of fussy.
Well, we required shot a 3D over the dome, we acquired adjacent, we merged it, we did our geosciences technology group, did a lot of special processing and we depth migrated it to give us this image. And here is the top salt, here is the salt dome here. And here is what we’re very excited about are these horizons beneath the salt. We have a structure both beneath the Lake Washington Salt Dome which is very, very attractive.
Now, we recognized this early and we’ve seen some risk and we’ve done a considerable amount of work to reduce the risk here. And I’ll explain to you why this is so important to us.
We studied the, one of the issues we have with below the dome is reservoir and how do you get reservoir there. I’m going to show you a well that Terry mentioned earlier, there is an Amoco well that actually drilled previous the dome in 1989, 1990 and they logged reservoir there. But you really have to understand why it’s there and how it got there before you can be comfortable with it.
We studied the regional geology and the depositional environments and we recognized that there is a major delta that said a lot of the sediments and provided are the sediments for the deep water fields and I’ll show you a little bit of that more later. We’re sitting here as this Lake Washington.
Now here is the Amoco well, and what we see is these nice sands beneath, this is beneath the salt. We’re down here 21,000 feet in depth and we see these sands. And then these red flags are some calculated pay through petro-physics. Now there are cores in those that have some oil shows. So that gets us even more excited and there is a number of reasons.
We have oil shows and good reservoir, so we have got reservoir, we’ve got hydrocarbons and we looked at the samples and the samples are friable, they are disaggregated they are – when you take them out they just – it’s like beach sand. And that’s really important because of these depths, 21,000 feet that thing start to happen drops. They start to get some minted, the porosity gets occluded that’s not happening here. This is just like the reservoir on top of the dome. And in fact the core – as the core analysis tells you that you get porosities up to 30% at 18,000 to 20,000 feet and you get some measure to permeability is that 100s of Miocenes. So excellent reservoir, we’ve got oil shows and we’ve got a depositional system that tells us that this reservoir is distributed on the structure.
There are hundreds of wells in the shallow section and these are just a few of them. What I’m trying to point out here is, here is the Amoco well that’s drilled through the salt and their horizon is here. We’ve tied these horizons around the basin into of Burr offset wells, these are the wells we drilled over here called Jasta, here is wells on top of the dome so we understand the distribution of the geology and the timing out here very, very well.
Now, one of our concerns was gas, natural gas. And as you get deeper rocks get more formally mature. Things get hotter and you get gas. And in the Lake Washington Beta Shane area, Lake Washington is very, very oily. And Beta Shane is very gassy. And that kind of – we didn’t understand that. And we had a model that this distribution of oil and gas was controlled by the source rock and we thought that there is a variety of source rocks out here in this part of the Gulf of Mexico and we thought we might have different source rocks sourcing it. And we wanted to understand what the phase is going to be below the dome.
So, we sampled all these into geochemical analysis, and what we found is in fact they are the same source rock and not different. And so that confused us for a moment. So we started mapping the horizons at the time of thermal maturity. Now what this means is, here is the Lake Washington dome, here is the Beta Shane dome, so what we did was we made a map, when this source rock is down below was generating hydrocarbons what did the world look like.
And so, Lake Washington already existed as a structure. So the hydrocarbons are all traveling in that direction. And they’re accumulating in Lake Washington very early, the early maturation was oil well, and that’s why you have such a heavy preponderance of oil here. Over at Beta Shane that structure hadn’t been created yet. And so the hydrocarbons are just passing through and going over to Lake Washington, so that’s in the very early in the cretaceous during the peak oil generation.
Now oil is still being generated today as we speak. But it’s gassier. The structure still persists Lake Washington, Lake Washington is still receiving charge, Beta Shane structure exists and so it’s getting a gassier charge. So why do I tell you all this, what this means is, the likelihood of having oil under Lake Washington is very, very high. And then that’s supported by the core analysis in the Amoco well which shows condensate and oil staining. So, our concerns for having a gas phase in Lake Washington sub-salt are very, very low.
Now, what’s our model? And this is a illustration of the model. We know that there is a deltaic system here at Mid Miocene time, the time of the reservoir in Lake Washington deep sub-salt. And it’s feeding the sediments here, the sediments come down into the deep water of Gulf of Mexico and these sediments, here is Lake Washington sub-salt. The same Miocene sediments that are being deposited here are the Miocene sediments that supplied the fields like Thunder Oars, Atlantis, Bull Winkle are the more east of the Flat Rock, all these giant fields in the deep water of Gulf of Mexico.
Here is the field size distribution and discovery order of those deep water fields. And what I want to point out is this line here is 200 million barrels. So, anything in magenta is greater than 200 million barrels. And you can see some fields exceed 1 billion in barrels of cumulative production or EUR. So very, very large field sizes in these mid-Miocene deep water fields.
Now, I want to show you our analog or an analog. Here is Lake Washington Dome here. This is a salt. Here is where we have done all that exploitation, we’ve produced with 300 million barrels and then produced here, here is the structure beneath the salt. And these are multiple horizons that we’ve mapped regionally across the area and here below the salt.
This is an early picture from literature of Thunder Horse. Thunder Horse is mid-Miocene development, here is the salt. Look at the image, noisy data, they have improved that exponentially and they have got a great image now but early days it doesn’t look too similar to us and you can see their horizons coming right up here. So, this Lake Washington looks very, very similar to Thunder Horse. And Thunder Horse is 500 million to 1 billion barrels of oil.
Here is a structure map on one of the horizons below salt, here is the salt. Here is our closure. Here is the Amoco well which sits way down dip of the crest of the prospect here, this had shows, this had reservoir, the reservoir extends up here, they didn’t even drill to the bottom of the section. We intend to drill. Here we say 20,000 feet plus, we’re still working on that. But we’ll, at least drill 20,000 feet but we see perspective interval down to 25,000 to 26,000 feet and we’ll work through that. So, we’re up 800 feet from the Amoco well.
So here is the success case, and we – these are the parameters that we’ve used. The output will be 5,000 barrels of oil per day per well. And that’s not inconsistent with deep water fields in fact, some produce 20,000 barrel a day.
We have estimated EUR per well of 4,867 million barrels or 4 million barrels per well, excuse me. This is, those carry risk. And we have the piece invest for this first well of 32%, appraisal wells would be 60% and our development worlds would be 80%. We’re working on well costs, we don’t have a finalized number but $20 million to $30 million per well. And to develop this would take 50 wells.
We’ve got 3D but to do a full development we probably want to improve upon that. We’d acquire some additional 3D, we’ve talked about securing partners to share risk and we’ll be working on that. And we planned to spread to exploitory well in the next 12 to 24 months, that’s just going to depend on number of things but securing a partner and working through this. But we’re very, very certain that this prospect is there, now we just have to work out the details of how we drill and who we drill it with.
We’ll test this well immediately after we drill it. We can test it to a Lake Washington facilities, they are right there. They are capable of accepting a considerable amount of oil per day and so that will make this an easy well to test. And then depending on that test and appraisal we’ll have to rescale our facilities because resource potential here is 200 million to 350 million barrels.
So here the full psycho-economics, about greater than 1,000 acre structure, 50 wells to develop and take one and half billion dollars to do this. They all rise 11 and the oil is 630 so this is a huge opportunity, payout in 28 months and MPV 7.7 Billion.
So with that I’m going to turn over to Bob and let him summarize. Thank you very much.
Okay, thanks John. Just to wrap up I wanted to try to characterize what you saw here on the development on the exploration side from a portfolio perspective. First I want to talk a little bit about the way we see the characteristics of our portfolio, first we have a large component of oil and liquid rich properties in our portfolio.
Secondly I think we have a balance mix of near term growth redevelopment projects and longer term growth through exploration and exploitation style of projects. Thirdly we have a large component of projects with production and reserves growth repeatability and fourth we have a balance mix of development exploitation and exploration which can reward anywhere from little risk reward all the way to high risk high reward.
Then all of our projects are benefiting from utilization of modern geo-science drilling and completion technology. Everyone at the projects we are involved with, we want to make sure we are applying the best technology we can to get it right as soon as we can and lastly, one nice thing about our entire portfolio is we are close to infrastructure and markets. We don’t have to access or create new markets for products, right in basins and areas where all of these exist currently. So we like that attribute about portfolio a lot.
Well, they kind of show you though our portfolio life cycle, just to put all of these opportunities into perspective. Where are we on the life cycle of an oiling gas offset? If you see down on the left hand corner, those are our new place. We identify where we are with the lake Washington somersault, the Niobrara, we have another play we are working on in Louisiana we are not quite ready to talk about and then as we kind of move over in to the evaluation appraisal face, you can see the McMullen eagle for dry gas.
We are not very far along with that, we are not committing capital there. The Wilcox, we are just starting, so very early in the life cycle on this Wilcox. The Web County Fasken range, Eagle Ford , very high value property but we are not progressing that because of lower natural gas pricings. The South Eagle Ford we are just kind of bidding from the evaluation appraisal phase into the development manufacturing phase to a lot of running room on the life cycle there.
Then you can see the McMullen oil, Olmos in the McMullen oil Eagle Ford. They are just kind of getting into that zone of ramping up now. The Osten chuck in general probably about 30% of its life cycle if you look at what we’ve done in masters creek but we have a lot of renting room still to go in that asset in both fairly.
Then Steve presented the Lake Washington LICC Sands, these are the deeper sand. We still have a long way to go there. This is our Lake Washington deeper projects, we are not even halfway there on total resource potential or life cycle of that particular interval. Then we get a little closer up into the more mature field into the harvesting mode bid of shale which is a gas commencing field much further along and then the Lake Washington Shallow sands, the LICC sands. We are kind of getting into the harvest mode on those shallow sands.
So this just kind of puts our portfolio into perspective, it might help clarify where each of these are in their life cycle. What we showed you today is kind of a portfolio value profile. The first part, these are resource place, we are looking at 0.4 development scenarios. You can see Texas, that La Salle Eagle Ford area that Steve highlighted as a program, a three ring program and the McMullen Eagle Ford Almost a combo program that Steve highlighted as a three rig program.
Again we have a 180 well locations to go in the La Salle County 309, in McMullen County. Rich return 3-4 oil lives and point for our project economics that we have our facilities in place are all greater than 100% of that piece of development. Down in Burr Ferry field our resource potential net to swift is about 11 rim and numbers on 36 well locations which are 100% locations and that to us will be half, about half of that. 3.2 oral wise and about 210% rates return.
Moving in to our conventional might seem place, individual well. Steve went through some of these with you but are we completion opportunities. We have about 3-6 Million MMBOE potential left. The A through K sands about 6-10 Million, the LICC sands about 6-85. These projects enjoy very, very high margins, high rates of return. The week completions are 100% types of rates of return. The A through K sands are 300% rates return type projects and the LICC are about 386% rates return. Then B to shale, the LICC little gas here, about 5-65 of MMBOE of potential remaining and project economics and about 50-85% rate of return.
Then John talked to you about our strategic growth. Three very different kinds of projects which we quite excited about; the first, they are very low risk, exploitation development opportunity using our modern technology that we’ve been working with in South Texas. About 20-28 million barrels of oil, equivalent, rates of return of about, the return of investments of about 4 and the internal weights of return of 183%.
The Niobrara is a resource type play 125-200 million barrels resource potential, lot of location between the upper and lower smoky hills members of Niobrara. About three allies and rates return of about 72%. Then the big higher risks, high return prospect, the Lake Washington somersault. 200-350 MMBOE potentially 50 locations be very repeatable if we make this discovery. Huge oil lines and rates of return on a property like that because of its close proximity, the infrastructure and the immediate timing to get into development mode.
So I wanted to just conclude there and kind of wrap up what you saw today in terms of different types of opportunity and how they look from a portfolio perspective. The drivers for 2013 performance bliss, the way we look at it, in Texas. we have to continue improving our IPs and our EURs and continue driving our costs down. In both the Eagle Ford and the at most program, that is a key goal for the operating unit.
We want to successfully get our compression in a timely way in South Texas and as we mention, we would like to bring in a partner for a select piece of our Eagle Ford development. And we want to do that for three reasons. First we want to improve our project returns and capital efficiency in this type of play, second we would like to achieve value by shortening the development time allowing us to run more rigs and bring that value forward and thirdly we would like to achieve some immediate recognition of the value for this position that we feel like we’ve delineated the risk and have the infrastructure and back bone in to get into the immediate development and manufacturing mode now.
Then down in Louisiana we are drilling a nice Jelly Bowl offset, and Lake Washington that’s a key project for us. We want to continue with some success in the (inaudible) as you said deploying this well pack packed for technology and getting those types of results. Then on the strategic growth side, we are doing some things. The South Bearhead and three horizontal Wilcox well we are in the lateral now. We want to test this technology out there in a very oily high margin.
Oil cast the Niobrara position out in South Western Colorado and thirdly we want to form a high quality partnership to drill an exploratory test in the Lake Washing subset this year. So with that, that pretty much includes the operating group and I’ll turn it over to Alt now to do a financial review force.
Thank you Bob and great job. Good to roll up to the volume here. Good to go. Okay. Let me you how we are going to finance all these great stuff, obviously great deal number of opportunities in our portfolios, we are excited about. We got to try to balance strengths and to get it financed and try to bring forward in the value that we can. Let me start off by pointing you to slide two or three which is a cautionary statement. We are going to have some information here that is obviously non historical. Going to be forward looking our guidance of our guidance out there. this is not going to change the guidance. No orders any of the forward looking stuff constitute guidance so I want to make sure that that is clear.
Okay, let me talk to you about Swifts financial strategy, it hasn’t changed much in our 30 plus year history. The company we’ve always been very fiscally disciplined as try to optimize our capital structure, strong balance sheet to keep the appropriate mix of equity and debt. Always looking to maximize our financial flexibility, little leverage, high liquidity has always been a mantra of ours. I think we’ll show you that today and obviously all we are striving to maintain and improve or credit profile and our ongoing basis.
We are very involved in helping the operations folks and partnering from a value creation standpoint, that’s something that always a keen focus of ours. Allocating capital, you’ve seen the opportunities we’ve got. It’s stuff to balance a portfolio and allocate the capital in the appropriate manner but it’s always a focus on risk versus reward. We also strive to balance our current opportunity seen, it’s kind of how we talk to you today about our development opportunities. We balance that with the strategic groups projects, we have exciting and sort of lay the foundation to the future.
We also get involved and looking at and evaluating in the complimentary and that credit funding strategies where there is a JV bringing in a high quality partner for some more expensive opportunities. Anything we can do to sort of bring forward the value and accelerate the present value of several opportunity set we get involved and plugged into that and we talk to you about some of that today. We also are clearly involved in the risk management process, we’ll show you a little bit on that today in a couple of slides but just from a general helicopter view, clearly we are responsible for identifying a critical financial risk that are inherent in our business.
We look at those, categorize them, try to decide what financial risk can we avoid, what can we transfer contractually, what can we reduce or mitigate and then some you just got to accept either it’s cost prohibited to attempt the mitigated of just it’s going to be a high dollar economic effort to try to mitigate it. Then we clearly lay forward our layout and mitigate those risk wit either through our contractual being paying attention to the details in our contract providing insurance, where that’s available or even hedges clearly a form of risk management transfer of risk there that we are most familiar with.
So that something I think that we do a very good job. We’ll talk to you in a minute about a little bit of a shift in our strategy on hedges but from a contractual stand point or legal review, everything we do, our insurance profile and paying attention to the details. I think we are very talked to with respect to that effort and very proud of that effort. Here is our capitalization, looking at the strong balance sheet. This has taken the last to publish the annual balance sheet, the end of 2011 and then on the right hand side is where we ended for 2012.
Most of you I think are very aware, but just kind of to take you along the lines about thinking is how this progressed. In the light report of 2011, we saw 2012 as the year kind of the inflection point of out running our cash flow given the opportunities that we had. The need to sort of accelerate some capital spending in South Texas with the shell playing very capital intensive activity as you are well aware. So we prefunded that with an offering, dead offering in the line off point of 2011, very well received $250 million bond and that’s why we have cash on the balance sheet at the end of the year and thought we had effectively pre-funded what we thought to be the cash flow short fall for 2012.
Well, gas prices ran away from, in geo-prices ran away from us. We had a hurricane event, we also were victims of our own success and that we were still efficient in the drilling. We drilled more wells than we had scheduled but I ran a little more. Fortunate to be able to term that out by doing an add on in October 2012 to 20-22 bonds which ended up being a very good laddering our debt. I think the next slide demonstrates that. If we go towards the high end of our leverage appetite, you know we are 47% death cap and right now it looks 2012 just with the basic plan that we’ve put out there for guidance with outrun cash flow over a little bit there but still be at a comfortable level of 50% metric cap which is one of the metrics that we look at.
So we still got the strong balance sheet, still got plenty of liquidity although we are keeping a key eye on this as we talked about this other strategic opportunities that we have that could be creative as far as the financing activities. The credit starts at the bottom there, rolling up each year end again you got your coverage ratio there sneaking up on three times which is kind of our internal metric that we work out there. Just work up again above 50% and then you got your debt to approve reserve on a part daily basis which is still very comfortable level giving what prices are right now.
One metric we look at is our leverage tp PV10 kind of 25-40% is been our internal metric that we’ve been comfortable with. This demonstrated, looking back three years the PV10 run on the LICC pricing basis and it compares that to the actual October debt we got outstanding and then shows the dry pattern we’ve got with respect to any facility among above that. So again, it shows we are not getting to far out of our skills relative to this particular metric. But again with the high end of where we’d like to be, I don’t think this is a good slide to demonstrate the laddering of our debt.
Our first maturity in 2017 and then with the add-on we did to the 2022 bond, we got some scale there relative to the size of that debenture which we tell, which folks tells us that use more liquidity and more effective pricing. I’ll actually price that, that offering that we did in October 2012, to effective defective yield with below 7% so it’s the best yield that the company’s got on any long term debentures.
So we like the laddering there, kind of terming out our obligations with our long-term assets obviously. We also in the line report of 2012 extended and amended on borrowing base. The borrowing base is currently set at 450 million. We’ve got a very strong bank group, 11 strong banks I think each bank is probably represented in this room so we appreciate what you guys do and allow us the flexibility to take advantage of all the projects we got going on. The two main covenants that we got are obviously in our bank line and they are basically a current ratio covenant in a coverage covenant both of which we are not even remotely close to trip a lot there so that’s kind of a snap shot of our financial flexibility that we’ve got and maintain.
There is just a little back four years our historical credit stats, obviously with some of the additional debts we took on in 2012. The comparison are on a prove reserve basis on a debt the cap went up still at a comfortable level for us. Then the two comfortable ratios at the bottom both neck and the debt have it out and of course your interest coverage ratio on the light again are at levels that are comfortable for us but kind of hitting the top slide of where we would like to be. Talking about our capital expenditures on the left we kind of show that.
Historically attempted to be relatively cash flow neutral but it shows in 2011 and 2012 how we kind of had to outrun, kind of kick start our shell activity. But it can show, it shows the different compliments of our historical spending on the left and then it shows on the right our current guidance which is 440-480 million for 2013. The lion share of which 75% plus is the developmental nature, we still got some facility activity that we are expending cause, but that price lies is shrinking.
It’s where we are still some prospects generating type calls that we’ve talked to you about today for the strategic projects we mentioned today as well as some that we haven’t yet talked about that we are looking at and planning for future success that we’ll talk to you about in the future. And we always have a discretionary price rise if you will based on activity and results and pricing within, we can either totally pull that out or we can scale that up if need be relative to the forward plan.
So again, just looking at our cap that’s always a good slide to demonstrate that. And here is the same information really just bisected area. Obviously 75% plus is going to be spend on our South Texas area down on the shell play on the Eagle Ford Olmos, South East Louisiana, yeah you see the numbers there, central Louisiana and the strategic growth. What’s when folks talk about our strategic growth and some of the opportunities we see there, they have asked before how much money we are going to be spending on that.
Well again we’ve been planning for that as we go and we are going to find it in different ways but from a standpoint percentage of our 2013 budget it’s less than 10% so some really need upside opportunity there. it’s a pretty low capital involved in 2013 for that. You’ve heard mentioned today a couple of times but pictures in worth a lot of words, we’ve every barrel of oil we sell right now in Texas and Louisiana and all are really awfully queries are anchored to either HLS or LLS pricing.
A lot of people have assumed we are talking 18 months ago and this kind of jacked out that it might be a month or two and then it was going to come back in where you can see here at least looking back 12 months that we got, takes us 12 months here is what’s showing. 12 months ago today we were up, the gap was $20 and everyone swore we’d come back here and we came in a little bit. I think it’s kind of just under 10 but it’s got back up to Almost $20 built and what you’re seeing here is really the take away.
Obviously from this slide is the nine max at the bottom bar that shows you the pricing and what transpired there and it shows you how brand HLS and LLS has effectively paired along each other in the last twelve months so you got the spelling there. But 100% of, given the location of what our crude has produces. It might cost you a little more for example in South Texas there is a transportation cost given down to cooperates we needed this pricing. But you are still anchoring to the higher pricing so we are effectively getting a premium and all the oil we sell in Texas and Louisiana which are clearly a lot of our peers can make that climb.
I mentioned in the intro talking about risk management, where clearly one of those profiles that you look at is pricing. Most of you likely know that historically swift has had a little bit of a different approach to price list management. We have used typically four of our participating colors to lock or protect against the precipitous decline in pricing that kept 100% of the up side. We looked at it as interest. It had a fixed premium; you were paying a premium to ensure against a precipitous decline in prices. Fourth quarter 2008 regretfully was sort of a poster job. We had 50% of oil and 50% of our natural gas hedges with flaws. That’s the good news, the bad news is we had to collect on it. but we collected over $30 million which allowed us to bring the plane in a little bit softer landing and it accomplished exactly what we would, what we were set out to do so from a price risk management point of view.
One of many reasons that we historically have just used flaws is with the location of our production, obviously you know the last several years, a lot of our success has been the South East of Louisiana. A lot of wonderful reasons pricing in other words effective as oil versus gas was good but that’s the good news. The bad news is it was hurricane early. When you basically swap out your hydro-card and it’s sort of a warrant to deliver that so you can see and you seen some companies get in trouble where typically some offshore ones when all your production is shut in and you swap it out you effectively have an all tries that works against you.
So, but because of now, our diversification of our hydro-carbons because of the fact we are down at a shell play where it’s a lot more predictable from a production stream point of view. We are looking at, we are postured, we are positioned at the right time to do some swap or do some long term colors or do some long return forward physical sale. So we realize and recognize that you guys have been asking for that for years. We think we’ve done exactly what we needed to do historically but we think right now what we need to do is to layer some of that in to our portfolio as part of our portfolio from a price risk management stand point. So you’ll be seeing that from us.
I hope to tell you and in the not too distant future because that means the prices had straighten and it had gotten up to a point where they are going to pull the trigger and do some of that. So typically we’ve target 20-50% of our physical volumes. Might go a little higher than that when we brand in the different types and it kind of goes without saying but the time to do that is to buy into the strength when the price is strengthen is when you can lock in the price that have worked for you. The stand point but again protecting your cash flow, protecting your margin, protecting your returns, it’s all, and it’s clearly the right knick. It’s a good compliment to solve all those.
Okay, we’ve provided you obviously with 2013 guidance; we’ve given you a lot of information as we always do in our analyst say. We shore you a very helicopter view model just to kind of get you all in the frame. Everyone does their own modeling but this kind of tells you if you kind of in the fairway, how a guidance shakes out. So what we’ve done is run it through a model.
This particular model we ran, we choose pricing in $95, 9 mix NGOs is a about 35% of a mix sole price and then a gas at 350 which at least of yesterday was in the ball point of 2013 strip placing, it’s a daily change in all three of these. But with this 2013 guidance reduced our low and high case production assumptions and that’s really the only thing that’s change. I think relative to the other guidance side we sort of picked the mid-point of whatever the guidance was and landed to a model.
And slide number 215 our results are that. It shows on the little case which is again little and high relative to the range of production that we are anticipating. It shows revenues up in the 600 million range, shows cash flows on the 300 million range. You see the PS range there and cash flow per share on the $7 plus range then we basically shows you, run some scenarios or sensitivities. We just a pull the high case production and then ran it at plus or minus a dime relative to gas and plus or minus a dollar relative to oil you can see the results there.
On a pro sure basis about a dime on those and then and then on the earnings basis about a dime on those and then on our earnings basis 5-6 cents per dime or dollar up or down relative to gas or relative to oil. Then when you sort of look at that, okay, where does that put you relative to your credit stats still the level from a coverage stand point, interest coverage comfortable level in the 5-6 range. Your debt, but that’s gets accepted about three times on which is the high side of our comfort level. 50% high side on the get it curve and then you can see the pro barrel and then of course the with the DO modeling so with that, I thank you for your attention and Bruce Vincent, President of Rise with Energy Camay is going to come up here and wrap things up.
Thanks Alton and thanks everyone for being here. I won’t take too long but I did want to kind of take a couple of minutes and highlight some of the things that we talked about today that I’d hope you leave well and thinking what else with energy today.
We’ve got three core areas all of which are heavily focused on crude oil and liquid rich area. The area providing the bulk of the growth in 2013 is the Eagle Ford sale in South Texas. We spend a lot of time showing you what we are doing there. Remember Steve talked about that resource factor in terms of learning here beginning with evaluation of threshold development manufacturing. Much of that is really ready to move into manufacturing and we not only delineated the areas that are heavily weighted and are loyal in liquid reach but we’ve identified for the portion of the Eagle Ford for sale and we believe is the most highly productive area of that. And we actually have well results that show you that we are doing exactly that.
The Eagle Ford is going to dominate much of what we do this year and we think it’s going to be able to provide that growth that we are talking about. But we also have that high margin production in Louisiana both Central Louisiana and the Austin Chalk and South East Louisiana, Lake Washington field in particular but also Bay de Chene. All those areas we believe will allow us to grow production, albeit in the smaller rule we like but with a significantly reduced capital budget.
You know, we’ve recognized we’re a little more leveraged and we’d like to be and so we want to out some capital biz for that, we’ve pulled spending back, really 30 to 40% which is the furthest significant amount. Although we have some strategies that we are developing to try to expand that capital, spending primarily with regard to the joint venture that we talked about it a couple of times, and I will spend a little bit more time on it. We find ourselves, we have good core areas and crude oil and liquid rich areas, they have good growth opportunity.
Land aside growth, hopefully you walked away understanding the visibility of that growth that we see in crude oil and liquid rich areas, not just in our identified bread butter business but some of the growth areas. The Eagle Ford in particular, we’ve given you a lot of information today to tell you that we believe that we can accelerate that growth. It’s a very well delineated area, we’ve now identified what we believe is the best part of that Eagle Ford delirium and it’s time to try to accelerate the present value and improve the returns and improve the margins and improve the overall matrix of the company.
In Louisiana horizontal, Wilcox field, we are just beginning but that has a resource potential of 20 to 28 million barrels, just in three Louisiana non sales that John talked about. Colorado and Niobrara, Niobrara has been very successful particularly up in the De Juan basin area. We try to identify a portion of Niobrara where there wasn’t everybody else, but we could get in at a fairly low cost and we have been able to do that, we’ve put together fairly significant position related to the size of sweep.
Miocene a big potential area 200 to 350 big environs and we are going to make progress on that too and I am going to go over each of those milestones that we expect to accomplish which you could follow our progress during the year. But we are also accompanied and its always been a big delivery in low leverage oil liquidity, keep that financial strength in place, because that gives the ability to properly execute strategy.
This is better over here, now let’s go back to this. We’ll ask the, grab the mic for those that are on the webcast and so hopefully this will be picking back up, I am not sure how much that you got or missed. But back to financial strength the company has always been a big believer of financial strength, well we are a little more leverage and we would like to be, we do have a stable capital structure in place. It still gives us the financial flexibility and the liquidity to execute our strategy.
The funding is in place, for our current activity, you can see it, we can go execute it, we can go get it done, but we are considering other funnier alternatives and particularly a joint venture and some of our Eagle Ford trail in south Texas. Now it brings a little capital there or many gates, future capital spending through maybe a carried interest, but also allows the acceleration of that asset development and puts the benchmark out there of what that assets were.
But obviously during the year we are going to have quarterly reports, quarterly earnings, production etcetera and you should watch that progress. But we have also tried to lay out some other milestones that we expect to make progress on in each one of these areas. Let me kind of talk first about some of the strategic growth areas, Almost kind of going in reverse order in terms of timing.
Lake Washington, sub soft project, John showed you a lot about that that is obviously something we are pretty excited about. It’s not every day that you get to deal with subsalt, we affectively will be a deep water project that has a well penetration with a log and core samples. That show you that you got reservoir quality proximity and good measured permeability and all shows in comments they shows before you drill your first sub salt test.
There is also a mask in it but we think it’s a really attractive prospect, our objective this year or you’d like to get it drilled. We recognize that that’s something that’s going to happen this year, it takes a lot more planning but we really think the right thing to do with this, the best part of it is bring in a partner and that’s where we want to accomplish this year. Bring out our partners, get that done this year, put a time on together to get that well drilled and make it happen. We think that’s particularly important to the long term growth of this company and if it happens that’s a game changer top of prospect.
Niobrara, Niobrara is also an incredible resource play, a lot of companies are having a lot of success up in Colorado than Niobrara and some are. So we recognized that everyone needs to see something happen first, we are sales due, we need to go out and begin that resource factory process and evaluate the plan. But we identified an area that has the attributes that we are looking for, for resource play.
We’ve been able to successfully put together a fairly substantial anchorage position for us that will be meaningful if it’s successful. And now we’ll take in that next step, we filed for two drilling permits, we hope to have them approved solely by June and we hope to be able to drill that first well in the second half of the year. Our first well is not going to tell us everything but it’s going to tell us some very important things about the autumn of economics of the play.
Really confident the well will work, I think the question is going to be more of the economics of the play and what you believe you can do to drive the cost down and improve the ultimate recovers and that bit is just as we have done in the Eagle Ford. I think that’s going to be a really import benchmark looking out to the future. One of the thing that’s great about out Niobrara resource place and not only as all but it really is going to make an inductive to bring in a partner to help accelerate it and finance it as well.
I mean if you read out the numbers then I think we showed some of that, it’s obviously that we are going to require a lot of capital more than we think that we can handle ourselves, but we want to go out and take some of that risk out into play and then that’s the time we are going to bring in a partner. So we think that’s going to be a big piece of where we are going forward and we hope to prove that play up this year in terms of drilling that first well before the end of the year so that’s the benchmark to look for.
Wilcox, that’s happening right now. Now that’s a fairly due risk opportunity already, you’ve got your offset operators that have a couple of very successful tests in the upper Wilcox. We have got a field that we’ve developed vertically for several years and been very successful vertically.
So that filed is very well mapped so low permeability sandstone, it’s a little like the, Almost in South Texas, that was a low permeability sandstone that we had developed for 20 plus years that we thought or was a grueling multi stage wrap technology could be applied to that development and what do you know, it worked, it expanded the economic limit of the field and it’s been a wonderful asset for us. We think the same thing can happen to Wilcox and that 20 to 28 million barrel potential area is really just in three of those nine sand arsis and it’s just in the acres that we currently control. We think that potential is obviously expandable but that’s something that we just have to kind of step away there.
But what’s happening this year, we are drilling a well, we are drilling the vertical powered hole, we are glad that we corded, we’ve showed you that, we know we got good sense, actually we knew that before we drilled it because the field is fairly well to land in. but now we are turning on holes out landed, we hope to get that drilled surely and case inserted and completed in the second quarter. So the benchmark to look for there is a test in the Wilcox results, both IPZ or what, lowered costs, making the play more economic, higher margins, input profitability. Significantly D risk but again we don’t have enough money to do what we’d like to do down there. Not only there is more capital accelerated in PV but it also allows you to optimize some of this efficiencies in play development.
So we are really looking to bring in a partner to help in a portion of that, Eagle Ford sell development in South Texas, we hope to get that done by the third quarter and we think that will not only allow us to accelerate the development, improve NPV in the play itself, it will achieve some near term value recognition, it will put a benchmark out there for the market sales the equities were. But it also allows us, we don’t know what the ultimate structure will be but if you look at some of the other joint ventures that have been put in place, typically you are going to get cash up front and carried interest or you mostly get in, I don’t know how it works. But yeah you are either to get cash upfront or a carrier that allows you to reallocate capital which you might have planned for in the future to other areas, so that’s a way for us to continue expansions and certainly these other things that we are doing.
And then last, but I don’t think the least, Swift Energy is 10-10-10 plan. I think we have given you the first statements that all these tense are happening right now and we expect to carry it in through this year. 10% increase in the initial production rates of our wells, that’s in fact happening, 10% improvement in the ultimate recoveries in the wells we are drilling that’s in fact happening because we are placing these wells in the right place in the new port shell. And then a 10% reduction in our cost, all three of those together, substantially improve the economics and the margins of the play that ultimately get reflected in Swift Energy’s financials where we get improving matrix in relationship to what we were able to do last year.
And I will leave you with just what I consider the final proof statement of what we are talking about. We are just not talking about doing these things we are actually doing them. Making them happen and that’s what is going to make 2013 a good year for our company. We appreciate your interest; we appreciate your investment and time being here or listening here on the call.
And now I will open it up for questions, we have got to rolling microphones on both sides and we will have one hand held mic here so that only one of us is answering the question at a time. If you have a preference for you who you want to direct your question to, say so, and you might also state your name and affiliation for the sake of others in room.
Our first question is from Neal Dingmann with SunTrust.
Neal Dingmann – SunTrust
Great job went out today guys. I guess my first question is yours Bruce, for your attaining as far as some of the JV opportunities I guess you talked about Niobrara, and then over leg in Washington and your thoughts about you know is there a timing that you are looking at on that or if a certain it wouldn’t be met would you venture into another one and sort of bite that on your own, if you can just talk on both those place.
Yeah, why don’t I talk first about the Niobrara, as we have noted it’s still in its very early stages of play development and maturity although there is activity in the area. We think that we need to retch it up the value with our testing, get good code that and understand the lot better before we go in and get to do our venture but that said, that information will of course lead us to our next steps. So it’s a loan up capital program in terms of the initial development that we could go it on our own for a while. These are less expensive wells and if you know the area, we got in at such a good cause, we typically have five year plus leases, we don’t have the sure fuse on us there to get something done like some of the Eagle Ford acreage existed for lots of players.
But that said, once you realize that value or retch it up the value, I think it is appropriate because if you look at the capital of requirements going forward that’s a big program. If you take a long time to do it, that’s a delay in the PV, we are very focused as a company not just in the Niobrara but in all the areas of looking at these PV’s and trying to bring them in closer to the future.
So you could see us talk in this time next year about a joint venture there but again it depends on what happens in the near term with this well or maybe a follow up well that we could come in and do in that area. As to Lake Washington and the sub-salt, I don’t think we are going to drill that alone. When you look at the one well test, sure I think we could operate that and do it, it’s not truly deep water in terms of cost, it’s not deep water in terms of the complexity.
But it is 4000 foot of salt and subsequent wells are going to be difficult wells to drill. We definitely have to play a big operations role at the upfront to keep the cost down. Yeah we got infrastructure in the field, we can test whatever zones look appropriate so we are going to be significantly involved in that, but in the same way that we have talked about the Eagle Ford we think by taking this out to the industry and offering a position in this project, we can accelerate what we can do certainly in the development of anything we might find. But we can also get the advantage of the industry knowledge and have a partner of choice there, so we are going to be a little picky about who we have in it but I think we want to have a partner there and not go alone.
Bruce you want to talk about the Eagle Ford?
Well, let me just may make a couple of things that Terry said first and then I borrow, I think we have the luxury there of kind of planned that out. Obviously the external environment has some ban on it but in miles will prove up to play to some extent because your ability to get a better deal with the joint venture partner has a lot to do with D risk in the play.
Lake Washington, now I would basically remember just what you said, is we want to get a partner, we think we can, we have laid out a two year time frame obviously, if we can get that accomplished in it, we will get accomplished. I think it’s worth pointing out that there are some logistical issues, you know only a few rigs you can drill that well, you are going to need sort of kind of well held equipment if you are successful at 20 to 25,000 feet and the like of those a lot need time orders.
With regard to the Eagle Ford we certainly do have the ability to continue that ourselves, I mean we are doing that now. I think we thought about other ways to put out liquidity, potentially other assets you could sell for instance, that would allow you to continue that. We do think a joint venture partner though makes the most sense and will provide the most liquidity. It also provides the benchmark value and allows you quite frankly to accelerate that play. You know if you look at the pace that you might do on your own verses the pace that you can do with a partner, you NPV even for a smaller portion is a lot better.
Neal Dingmann – SunTrust
Okay I agree and certainly I will just ask follow up question, as far as South Bearhead Creek and Wilcox, two questions there, I guess one with which we have seen, if you see some successful result, your thoughts as far as just adding acreage there I mean maybe for Bob as he’s been acting there, is the acreage available and would you continue that acreage in that area given the financial support.
I have got the mic so I will answer the question fairly short and sweet is that absolute instant in acquiring some acreage and we are looking at some in the area now.
Let me add to that acreage question, you know it’s not a play like the resource play. It’s that we don’t see it as a 3 or 4 economy type play where geology in terms of structure doesn’t matter. We do believe structure matters in that play, so you won’t see us just be doing any kind of carpet drilling or carpet acreage acquisition.
Leo Mariani – RBC
Yes ready for the next question its Leo Mariani with RBC, just basic question Abel or JB, just trying to get a sense of where you guys are in the process, have you already kicked off a data room, or are you already talking to potential participants, just any caller you may have around that?
We have kicked off a data room, we have engaged a third party to help us with that and we are beginning the process of talking to people, you know it’s not something that just goes out there and is done quickly, we want to get the right partner. Ideally we’d love to have a strategic partner that perhaps could do some other things with us as well. So we do expect that to take a little while to get accomplished but we have begun it.
Leo Mariani – RBC
Okay thanks, and I guess in the Wilcox, you talked about some other ops that operate the wells in your presentation horizontally. Just trying to get a chance of who those operators were and whether or not are they continuing horizontally there?
Well the principal outside operator he has announced a couple as mid states and our preference is not to necessarily identify the specific names and then quite frankly we have figured somebody you knew we are talking about anyway. They just announced one like a week or two ago so they are continuing that effort. I think that they are planning to test the lower Wilcox well maybe later this year which we would love them to do as well because that’s in our plans to but not until next year. And the canar to the South west of south of Bearhead Creek has been doing some work in the Wilcox.
Leo Mariani – RBC
Again it’s still a structural play and based on our oil wells right now we think our parts are still doing vertical wells on structural targets. Should say I guess the EP energy I think. The former out pass of EMP group.
Leo Mariani – RBC
I guess, just one last one from me here, I think in last year’s annuals day I think you guys had talked about not doing a whole lot in the Almost for the next couple of years. It looks like you brought some activity back there, just trying to get a sense of maybe kind of what had changed last year verses now?
Gas prices, the Almost has been a wonderful, we would call it a rock at Jaboltra there in south Texas and as you do go south that hydrocarbon there I’d say is 1500 or 2000 foot a cordon. It’s one of the largest hydro columns in the world I think but we find gases so we keep going south in there and we do find some very significant sand development that’s more robust than we thought, but it takes the horizontal wells through that. We showed that last year, we showed a lot of the gas running room but as we drilled out that Almost and I think we showed that today, the oil tends to be more to the North and somewhat to the West. So we are still doing some of that but we, to count that phrase again we packed a lot of that Almost gas that’s down south of us.
Leo Mariani – RBC
I’ll say and that says you know last year we were looking at say 250 gas, this year it’s 350. I made a big decision that moves from in terms, I think you are going forward.
Well I think everything comes down to competing for capital right now and we still have so many good oil projects that gas is not just to get up there to reasonable returns, it’s just got a complete flagrancy oil project that are much more robust. Our fasken area we’ve got some extremely high quality rock over there and a 450 deck, it starts generating some really excellent returns. Again we wouldn’t want to do that unless we can lock in some of those returns because this gas market has been extremely volatile relative to pricing and our personal views, we are going to see gas prices go up. We could see some really robust prices 455, but we do see a lead on it because lots of other operators know where we could get gas projects to. So another gas cycle is out there somewhere.
Leo Mariani – RBC
Hi, (inaudible), a couple of questions, in the Eagle Ford, can you talk about the timing when you switched over to the new lateral placement and if I look at the 2012 completion that you announced, which wells that the third quarter completions or the fourth quarter completions that are in and out and fully switched out to the new techniques?
Yeah, we really started targeting the Brittle zone kind of in the middle of the year so if I think about the wells around the press release for PC Q7 age was definitely in the Brittle zone. The Kinley and Miyou was a well we had mechanical problems on and it was drilled earlier in 2012 so it wouldn’t have been a refined target zone. I think what else is on there, yeah the H3 and 4 for the most part were in the Brittle zone not quite as well as the PCQ 78 and then the Bats well is around the south. So the only one that wouldn’t have been would have been the Kilnya MNU, and then the sidance 48 is the normal’s and it don’t have to be steered as critically as the others.
We also announced fourth quarter completions in the earnings press release and some of those wells were in the brittle zone, some were not I’d have to go back and look at that to identify but you can probably tell by just looking at the numbers.
And then are you still making improvements there actually you mentioned earlier the PCQ well is Almost 1200 barrels a day, 30 day rate was I think the average for the 7 wells that you showed earlier was something like 700, 800 year oils a day. Is that…
PCQ 7 is in the same area as the Haze wells and the others but if you look at that trajectory it was Almost 100% in that brittle zone. The other wells weren’t 100% in that 60 foot in a robust so I think if we can stay in that 60 foot zone, we can see improved wells like we have seen with the PCQ 7 8 but it’s the only well that has been completely in that 60 foot zone.
Okay, and then in your 2013 guidance, how much of this improvement is factored into the numbers you provided so far?
Yeah we are going to hand the mic around to see who talks. We factored in that portion that we are highly confident in and by that I mean 75, 80% there where we’ve got strong data and we have already begun either with our stimulation services where we may have already renegotiated some contracts with our drilling progress. We factored a fair amount of that in, but when we say that we have targeted 10 10-10-plan we are talking in addition to what we factored into that budget. So we set some targets, we call them milestones that we want to report back to you on, so it’s not in our guidance but we need to continuously improve. As you note, we showed our major chart and we showed maybe a 10-20% improvement from the old wells to the new wells. We did not factor in for example what we are seeing on the PCQ 7, those are yet to come.
We have got lots of continuous improvement projects, it’s not just staying in the brittle zone, we are also looking very hard at the fracture techniques, we are using the kind of fluids and sands, how we space perforations and in fact number of stages, those are really critical factors too.
Brian Kusmo – George Weiss
I guess my first question was, I wanted you guy to reconcile the rate of return numbers that are here in the wells verses I guess the capital efficiency that you guys are diving to. Like every well looks like can have greater than 100% rate return so I am just trying to get to, like how did that get to the 100?
Yeah let me reconcile it first then I am going to throw it over to Bob because I think Bob did all the roll up of it. First of all I don’t think that there was a risk adjusted in the sense of you know, you have some wells fail and so it’s not representative of a composite risk profile. For example if you look at the rates of return that you would see on these wells by the time you also bring in facility, and I am not sure facility costs were in there, they were not. By the time you bring in facility costs you have to have an ultimate understanding of what portion of that facility burden is going to bear on every well when you are still in this improvement phase so you’ve got capacity that you’ve built out ahead of yourself. And then you’ve got your corporate overhead that’s not in that as well.
A lot of that rate return really, and I think you got to look at both ways, you have got to look at on full cycle corporate economics as well as individual projects. You’ve got to have the momentum and scale to really achieve those kinds of rate returns or proportionally a significant amount of a needed corporation. But Bob also well had talked for a minute about the price stakes over there. You know the actual returns we have been getting at least historically did include some dollar rated gas so that’s a big difference as well.
Yeah and just a little more, we kind of ran numbers for you different ways for different plan types. The Eagle Ford resource play, the Olmos resource play, we ran those as a 3 rig program, a point forward development of all of our parts, not taking into account what we have been doing with facilities and infrastructure it’s what we’ve got to do from here on now. Yeah or the 3D that we have invested so those were kind of point forward numbers saying okay what’s the value of this asset today at this point.
The Miocenes those were all individual well economics because it’s too hard to kind of put that in a time frame of development in a full cycle basis so just basically using the price decks that we showed you in the Eagle Ford and the Olmos starting out at about a $92 price deck about a 350 gas deck or 320 gas deck.
Accelerating over about 11 years up to a cap of $100 oil and $550 gas so those are the ways a lot of the economics are generated. On the strategic growth projects we just take that same deck and do a full cycle economics look at the project once it turns successful. So, that’s after the risk is been removed that we’re hitting the models that we say we’re going to hit. So, those were successful full-cycle economics for the strategic growth projects. So each had a little bit of a unique twist to it.
Brian Kusmo – George Weiss
Okay that’s good. This is another question is a little more specific on United pray or play, can you talk a little bit about why the previous operators were drilling vertically focused, were they focused? And are there reflectivity windows, pressure windows, over pressured area?
I’m going to take the first shot then hand it to John because I can just feel that he wants to answer that. The early wells are old wells, that was discovered quite some time ago so that was kind of the technology; it was kind of a backyard small operation area, that’s exactly right. These are old wells and there are a number of deeper more conventional targets that the operators in that area were drilling for. And a lot of these wells they encountered this shows and the Mancos where they exploited so they were not typically the original targets. And we have not had this real quality fracture stimulation plant till the last ten years and those wells were drilled 50 years ago, a lot of them and more recently tens of years ago.
I think a lot of it was accidental but then when they did find some things that worked they would continue to exploit. So we’ve taken the information from all the wells drilled out there and put together a model that we think is going to work very well and we have the benefits. One of the beauties of this place for us, is we have the benefit of a lot of data through this intervals that we can use to high grade our acreage position, that’s what we have done.
Michael Hall – Baird
Thanks, Michael Hall with Baird and Energy Investors. I guess couple of things from me, first in the Eagle Ford program as you moving in the development there, curiously you talked a lot about the capital cost improvement. Are there any forward looking kind of operating cost improvements that you think you’ll realize as you move further into the development, you know really worked on the economy scale and maybe quantify what that might be?
One of the things that I mentioned earlier was our water disposal and that project will probably cut 5 or $6 million off our LOE costs. Obviously with capacity and the facility as we bring in new wells we ought to have economies scale and continue to drop the cost but the big deal is going to be the water disposal.
Michael Hall – Baird
And any idea what that might kind of look like in a barrel, you know per barrel basis or perhaps of fuel basis?
You know, I know we were hauling water for 3 or $4 a barrel and we plan to cut about $5 million with the cost and I think that’s probably about half the cost, Randy Baileys in the back, if not Randy that’s about right. Okay he’s got thumbs up so disposal for hauling and disposes about $4 will cut that in a half or about 5 or $6 million a year off the operating cost down there.
Michael Hall – Baird
Okay great. And then in the, you know as you focus more on the Brittle zone, just curious, does that limit your ability to really push the pace in terms of drilling and in terms of wells? Are this required at your law?
No, it’s not having a significant impact. I mean if you are using a rotary steerable for sure it’s easy to stay in its own. So it really is not slowing us down a lot on the drilling side, we are getting pretty proficient at that.
Let me just add one thing, we also really have our visualization capabilities up so we are looking at the data in real time and it’s a lot easier for the whole system to steer these wells and keep them in the zone better. As I showed the projection of number of days on well coming down, cost coming down, lateral wings going up, we seem to have sufficient improvement to still keep that tightly steered using our visualization without spending a lot more time in that lateral section.
One other comment, it does take a lot of hard work by a lot of individuals to keep them in the zone, so you have constant communication between geo scientists that’s in the office constantly calibrating the sites and they talking to the drilling engineer. We also have an operations geologist on location looking at the cuttings so we making sure that our sites making is completely calibrated on an hour by hour basis but it takes that kind of effort to be able to do it.
Michael Hall – Baird
Okay great, I appreciate the caller. And then in the sub salt, just curious on the additional 3D, any thoughts and costs around that and would there be something you’d look to acquire prior to drilling or after?
Well we are working on all that, we are actually designing the program now and we are looking at a number of different opportunities to acquire this. We haven’t landed on exactly when we will do this, we will certainly do this prior to development, we think we can drill a well without this 3D but we’ll be consulting with our partners and have a discussion so it’s still up in the air on exactly when we are going to acquire this. But we have the technology; we are actually planning with the people in-house yesterday that are doing the formal planning of this program.
Just to add a little more color on that situation, it didn’t come up in the presentation but that Amoco well that was drilled to 21,500foot only took about 100 days so we have a lot of control there that gives us confidence that we can drill without additional sizing.
Okay, yeah I can’t help but when I had even more call, part of the reason that we wanted to file a final decision on that is the cost of drilling these well is materially less than if you were in the deep water. So that factor is in hard into the decisions, clearly for development you’ve got to have more robust 3D but I would remind you we do have 3D over right now.
Michael Hall – Baird
Okay, and then one last one from me, if I could, is the south west Colorado, the Niobrara prospect, can you review kind of what the infrastructure situation looks like there and well you expect a little price realization?
There is infrastructure in the area, we are planning the well we are going to drill and explore pretty well, so we are going to do, tests is efficiently impossible. We don’t have plans for constructing infrastructure until we get an idea of the scale and scope of this but there is pipelines, there is facilities, there is a lot of infrastructure and we are right on the flanks of the Santa Juan basement so there is a tremendous amount of groups that do that sort of work there. So that’s something that we are looking into, the marketing, there is a slight discount for the oil there, we’ve included that into our economics so not a big concern for us on the ability to export this harder covers.
Andy Coleman – Raymond James
My name is Andy Coleman with Raymond James, got a couple of questions on this, the sub salt if you go back to that. I guess could you just refresh my memory to as why in Amoco didn’t proceed with that well, and then it goes all super stand own?
Well, you know obviously I haven’t heard discussion with Amoco on that well so I can’t tell you why they didn’t but I can guess. And the first, the well doesn’t have what we can tell is movable hydrocarbon in it. It looks like the stain on the core means that there were hydrocarbon’s in the system going through the system and that’s proof positive that there are hydrocarbon’s beneath the salt for us, and that’s very good news. But for a company that was drilling a well in 1990 without any 3D, they drilled a well and they found some sands that were basically water wet.
Now you have to remember in 1990, that was when the first giant fields were discovered in the deep water gulf in Mexico. And Maoris field was discovered in that time frame, there were some slightly earlier fields (inaudible) and some others and they were finding several 100 million barrel fields out in the deep water of virgin territory for exploration at the time and that’s when the big rush to the deep water occurred. The gently sales and such so I think the last of onshore exploration was gone at that point and people all rushed to the offshore. So that’s why if I were and Amoco during those days and drilled that well I think I’d be out in the deep water chasing some giants there.
Andy Coleman – Raymond James
Okay and so your cultural then there is I guess oil down to and so you had closure on the structure with it and then you think about the probability of the sand, does that pose any challenges from a completion standpoint or is the pressure low enough that you can just grab a packet?
Yeah you go grab a packet, yeah its conventional technology we use all the time, it’s been around for decades. There is nothing but good news about the reservoir and yeah let me go back to the closure. Nobody had really any way to know what the closure was there because we shot at 3D. And so when Amoco drilled that well they certainly thought that they were in a structural optimal position so they probably didn’t see an opportunity or didn’t know where that next opportunity would be. So down deep as closure is really from our 3D work.
Andy Coleman – Raymond James
Okay if I can say, one last question, if you look on the book here I am not sure what’s the slight number, as in the portfolio of live cycle you got Lake Washington in basin in the harvest mode. Would those pieces of the assets be up for sale, in a private trade or a swap and if you are looking for a partner for this ID test?
Well as we thought things are complicated Lake Washington itself, if you are saying Chad, you’ll see the sub salt in the very early life cycle and then you will see the LICC sands that occur in the mid cycle. Unfortunately the facilities and infrastructure that sits out there doesn’t care. So yeah there might be something that we could do with some of the older production, it would have to be very creative and not give up the LICC sands or in lieu that somebody have some extremely premium value form.
But the test to looking at it is one asset at a particular point in its life cycle. It really has been on all aspects of that. Baby Chene, not so much so in terms of what we have shown you, but there are some deeper targets there that also may be sub salt like. They tend to be much more gassy in our view right now, clearly the deep like oceans and well will give us a lot of hand side about what we might expect over at Baby Chene and you know short of another deep prospect in Baby Chene. Maybe this come up on the right of the screen a lot sooner.
Andy Coleman – Raymond James
Yeah and then I think I had a probable question, the earlier in some of the slides you gave are cash flow profile out of the South Texas and looks like starting in the first year you are Almost at cash flow neutral program in those models. Looking at your guidance for this year looks like, even though would be still on pretty decent mind that’s cash flow out spent on this year and maybe going forward. Can you reconcile that if south Texas is a closer cash flow neutral program why they outspent?
The answer is really the same answer when we talked about capital efficiency. Those are done at project levels and they don’t incorporate corporate overhead and a lot of other things that you are spending money on are your other assets. So it’s just something done on the project level at that point in time, with was, when you are looking at overall cash flow you have got to sustain the entire corporation.
Andy Coleman – Raymond James
Okay, and then so if you sort of maintain your program as today, what’s your line of status to when the program gets to mobilize cash flow neutral?
Obviously we are working our way there that’s one of the reasons we pulled back capital spending this year. One of the key things that we have laid out for us to do this year is an acceleration project and the Eagle Ford joint venture. The effective ability to do that will have a knowledge barrier on that particularly if it brings an additional company log for that all, carried interest, so we are better able to answer that question after that gets accomplished.
I think our objective is to try to work our way to cash flow initial, if you look at Swift Energy’s history, we’ve always been very cautious about managing our balance sheet and trying to spend within the level of cash flow recognizes there are periods of time that you do outspend but then you got to work your way back into it. Can you hear me?
Andy Coleman – Raymond James
I had a question for Bob on the Gulf coast volume guidance, the 6500 to 7,000 barrels a day, does that assume risk volumes for the deeper jelly bolt target and orders and mainly re-completions?
No it does include some drilling activity; all of those numbers are risk numbers into those profiles. So yeah there will be a risked outcome of the jelly borehole, well into that lighter blue wedge that you saw on the book.
Yeah its gross, and they would also be risking on the rig re-completes from a mechanical standpoint and as also we have a historical downtime and so there is downtime on existing base also. Then we use historical data for all those factors.
Andy Coleman – Raymond James
Got it, great. And one follow up, in terms of the JB talked about having adequate take away compression processing, transportation agreements in place for the Eagle Ford, but if you do the JV in ramped up activity how much capital do you think would be necessary I guess?
Well I think out in LaSalle County, obviously if we went to that 3D program and opt our pace, we would have to access more takeaway capacity to get to those big volumes. We have enclosed discussion with a lot of the market for takeaway capacity available but they are going to want you to sign up for that so we wouldn’t be comfortable doing that until we reach some sort of an agreement with the partner, the pace of the development activity.
And then we would begin the truncheon into additional takeaway capacity. In terms of the infrastructure, we really do think a lot of the main backbone is behind us, Bolton, LaSalle and I have a flask in the McMullen County as well.
So obviously there is still going to be more gathering, more tank batteries, things of that nature but we are beyond a lot of the major investment in our own infrastructure and backbone. It would be more of a matter of accessing additional trances to takeaway.
Yeah and the more the slide that showed we had 20 tank batteries across the whole of south Texas so we really have most of the tank batteries in place. If we went to a 3 way program in a certain area, you might see some minimal capital to add additional equipment to that tank battery but like Bob said, the majority of the equipment is there.
Steve Barman – Canaccord
It says, Steve Barman from Canaccord, really just a question of Alton. You talked a lot about oil pricing and are you getting great pricing there? Can you just talk a little about compensate pricing as we sit here today.
Yes, you know I think, my discussion was on that slide that we were talking about the difference between the brand and Imex and obviously HOLX, so LLS and what we were getting there obviously in the south east Louisiana area we are giving the highest premium and there is not really a reduction from the standpoint of the quality of that crew and I think we are giving the maximized number.
I think from a standpoint of south of Texas there is a slight deduction that we are seeing ahead of our marketing groups in the back. Dollar per barrel range, oh, Bob’s got that.
I can help with that a little bit. On the gravity adjustments on the condensed really the break over is about 50 degree API as you get about 58 degree API we are taking more of the deduct. As we are under 50 API we are not seeing much of a deduct. But the good thing still about is we are linked to LLS so we are working backward from that so even with the additional gravity deduct we are still strong to neimax pricing. Even out into that lighter condensate in our toss wells.
Let me put a little bit more commentary and because when we say slight deduct you know everybody tends to think of anything coming off from Neimax. And relative to Neimax we have a premium in the crude and oil. So it’s an interesting well where you have 34 gravity or 36 gravity crude oil and then you got 40-44 gravity condensate because sometimes you mixing them and it doesn’t make that much of a difference on the take away but sometimes you better not mix them or you get a horrible result.
Right now there is more condensate of a higher gravity, the 45-55 level coming out after. Texas is probably going to grow so you probably going to see more deterioration in the relative price. We are looking forward, we are not taking that $20 premium that we see on OLSS relative to 9x. we are not assuming that’s going to continue so when we talk about slight deducts, we are not talking about half of the $20 if it’s stake in place. You can be seeing the $7/9 deduct on the condensate.
Steve Barman – Canaccord
Mark Lear – Credit Swiss
Hi Mark Lear from Credit Swiss. My question is just around liquidity and leverage and your though process and why joint venture in the Eagle Ford is your best alternative to I guess right the ship in that regard. I’m thinking that the asset itself has been de-risked and optimized operationally. It seems like execution there is getting better. Why not think about monetizing other aspects where the market probably isn’t giving you as much value creditor. There isn’t as much outside or are there alternatives other than legal front.
Well, I think that’s a good question because at the end of the day we want to improve our metrics, our actual return on capital, that the critical thing. Getting recognition for value, that the critical thing for us so I wouldn’t say that a partner in the Eagle Ford is the cure all for everything but if we have a partner or we create a partnership that can accelerate and bring some present value that’s out in the distance forward and give us more growth momentum, we have to look at that. There has to be cleave on terms of what we would do.
It has to definitely give us better returns that what we would do and it has to be obvious to our shareholders that it was the right thing to do. So we're not going to just do it, we are looking at other ways that we can accelerate the Eagle Ford now. Clearly a 3 Week program is not that difficult to manage from an operational stand point. We’ve got folks, we’ve got the infrastructure and as they’ve noted we can keep it up and do that. So the short answer to your question is yes we are looking at all those things and no, joint venture in the Eagle Ford is not absolutely necessary for this other things or better alternatives for us.
Wilson Sbatcher – Johnson Rice
Wilson Sbatcher Johnson Rice. Admittedly it doesn’t look this is the case in the geo laws of the new wells, but with the lower landing at the lateral and the Eagle Ford, do you think you can gain any contribution from the build off?
We’ll let our technical guy answer that.
Yeah I don’t think we are getting a whole lot in the newly steered wells, if you look at some of the older wells that were tacked in the whole Eagle Ford we didn’t get down into the builder. But we are continuing to look at the builder. We’ve talked about drilling a builder well because we think it could be productive, the problem with that is we think we get H2S from that budder and if you get more H2S its much more difficult to operate.
So yes we have in some wells and the new wells I don’t think we are getting an appreciable amount because we are not seeing the H2S in those wells. We are seeing better GORs but I think it’s just because its right in that organic brittle section and the gas is coming with the oil. Of course that better GOR helps lift that oil out that’s part of it.
Wilson Sbatcher – Johnson Rice
Great, and can you remind me in those Monaco acreage did you own the deep rights and is there any thought of this all test, you think you are too far down there?
Yeah, I’ll let John get that one.
Well we have actually looked pretty harder at the Piasol and we, Piasol is largely gas in South Texas so where we continue to study this I think we all look at the best place to test the Piasol but right now we don’t have plans to do so. And it is largely because of mostly dry gas. There have been some recent reports of oil and we are watching that pretty closely.
Wilson Sbatcher – Johnson Rice
Any more questions? Any more questions.
No more questions Bruce. All right if there are no more questions thanks for coming, we really appreciate your investment and time and enjoy the opportunity to tell you about what’s going on at Swift Energy, thanks. We have some delightful lunch treat for you outside and please feel free to grab a delightful lunch. Luxurious Swift T-shirt on the way out in a variety of colors and sizes. Thank you so much for attending and enjoy your day.
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